EQT (EQT) 10-K 20 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document and Entity Information	'	'	'
Entity Registrant Name	'EQT Corp	'	'
Entity Central Index Key	'0000033213	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$11.90
Entity Common Stock, Shares Outstanding	'	150,893,000	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

STATEMENTS_OF_CONSOLIDATED_INC

STATEMENTS OF CONSOLIDATED INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
STATEMENTS OF CONSOLIDATED INCOME	'	'	'
Operating revenues	$1,862,011	$1,377,222	$1,323,829
Operating expenses:	'	'	'
Purchased gas costs	148,708	134,951	127,903
Operation and maintenance	97,762	99,257	84,348
Production	108,091	96,155	80,911
Exploration	18,483	10,370	4,932
Selling, general and administrative	200,849	172,243	153,624
Depreciation, depletion and amortization	653,132	474,617	313,868
Total operating expenses	1,227,025	987,593	765,586
Gain on dispositions	19,618	'	202,928
Operating income	654,604	389,629	761,171
Other income	9,242	15,536	33,276
Interest expense	142,688	184,786	136,328
Income before income taxes	521,158	220,379	658,119
Income taxes	175,186	71,461	238,537
Income from continuing operations	345,972	148,918	419,582
Income from discontinued operations, net of tax	91,843	47,493	60,187
Net income	437,815	196,411	479,769
Less: Net income attributable to noncontrolling interests	47,243	13,016	'
Net income attributable to EQT Corporation	390,572	183,395	479,769
Amounts attributable to EQT Corporation:	'	'	'
Income from continuing operations	298,729	135,902	419,582
Income from discontinued operations	91,843	47,493	60,187
Net income attributable to EQT Corporation	$390,572	$183,395	$479,769
Basic:	'	'	'
Income from continuing operations (in dollars per share)	$1.98	$0.91	$2.81
Income from discontinued operations (in dollars per share)	$0.61	$0.32	$0.40
Net income (in dollars per share)	$2.59	$1.23	$3.21
Diluted:	'	'	'
Income from continuing operations (in dollars per share)	$1.97	$0.90	$2.79
Income from discontinued operations (in dollars per share)	$0.60	$0.32	$0.40
Net income (in dollars per share)	$2.57	$1.22	$3.19

STATEMENTS_OF_CONSOLIDATED_COM

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME	'	'	'
Net income	$437,815	$196,411	$479,769
Net change in cash flow hedges:	'	'	'
Natural gas, net of tax (benefit) expense of ($50,200), ($61,757) and $110,186	-76,489	-93,878	166,840
Interest rate, net of tax expense (benefit) of $63, $4,833 and ($5,720)	144	6,369	-7,433
Unrealized loss on available-for-sale securities	'	'	-4,896
Pension and other post-retirement benefits liability adjustment, net of tax expense (benefit) of $16,115, ($1,992) and ($2,752)	21,501	-1,085	-4,474
Other comprehensive (loss) income	-54,844	-88,594	150,037
Comprehensive income	382,971	107,817	629,806
Less: Comprehensive income attributable to noncontrolling interests	47,243	13,016	'
Comprehensive income attributable to EQT Corporation	$335,728	$94,801	$629,806

STATEMENTS_OF_CONSOLIDATED_COM1

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME	'	'	'
Natural gas, tax (benefit) expense	($50,200)	($61,757)	$110,186
Interest rate, tax expense (benefit)	63	4,833	-5,720
Pension and other post-retirement benefits liability adjustment, tax expense (benefit)	$16,115	($1,992)	($2,752)

STATEMENTS_OF_CONSOLIDATED_CAS

STATEMENTS OF CONSOLIDATED CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income	$437,815	$196,411	$479,769
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Deferred income taxes	110,363	95,185	234,019
Depreciation, depletion and amortization	676,570	499,118	339,297
Gain on dispositions	-185,894	'	-202,928
Provisions for (recoveries of) losses on accounts receivable	2,957	-1,235	1,581
Other income	-9,508	-15,965	-34,138
Stock-based compensation expense	52,618	40,230	20,080
Unrealized losses (gains) on derivatives and inventory	15,601	7,182	-1,497
Lease impairment	14,198	5,543	2,587
Noncash financial instrument put premium	'	8,227	'
Changes in other assets and liabilities:	'	'	'
Dividend from Nora Gathering, LLC	9,000	12,750	23,500
Accounts receivable and unbilled revenues	-44,818	-48,364	14,317
Inventory	30,090	43,277	1,117
Prepaid expenses and other	-8,248	-17,404	22,812
Accounts payable	53,527	32,275	42,262
Other items, net	46,127	-48,757	-37,758
Net cash provided by operating activities	1,200,398	808,473	905,020
Cash flows from investing activities:	'	'	'
Capital expenditures from continuing operations	-1,764,262	-1,358,246	-1,232,723
Capital expenditures from discontinued operations	-36,637	-28,745	-31,313
Proceeds from sale of assets	740,587	4,842	619,999
Proceeds from sale of energy marketing contracts	23,000	'	'
Proceeds from sale of available-for-sale securities	'	'	29,947
Net cash used in investing activities	-1,037,312	-1,382,149	-614,090
Cash flows from financing activities:	'	'	'
Proceeds from the issuance of common units of EQT Midstream Partners, LP, net of issuance costs	529,442	276,780	'
Dividends paid	-18,094	-131,803	-131,625
Distributions to noncontrolling interests	-32,781	-5,031	'
Repayments and retirements of long-term debt	-23,204	-219,315	-15,457
Proceeds and tax benefits from exercises under employee compensation plans	45,137	7,871	2,791
Proceeds from issuance of long-term debt	'	'	750,000
Debt issuance costs and revolving credit facility origination fees	'	-4,022	-11,738
Decrease in short-term loans	'	'	-53,650
Net cash provided by (used in) financing activities	500,500	-75,520	540,321
Net change in cash and cash equivalents	663,586	-649,196	831,251
Cash and cash equivalents at beginning of year	182,055	831,251	'
Cash and cash equivalents at end of year	845,641	182,055	831,251
Cash paid during the year for:	'	'	'
Interest, net of amount capitalized	143,187	187,884	129,486
Income taxes, net	$163,703	$27,605	$47,242

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$845,641	$182,055
Accounts receivable (less accumulated provision for doubtful accounts: $5,171 in 2013; $5,883 in 2012)	235,781	190,258
Inventory	19,656	45,165
Derivative instruments, at fair value	107,647	304,237
Prepaid expenses and other	46,700	38,451
Assets of discontinued operations	'	92,678
Total current assets	1,255,425	852,844
Equity in nonconsolidated investments	128,983	130,368
Property, plant and equipment	11,062,136	9,153,207
Less: accumulated depreciation and depletion	2,728,374	2,093,795
Net property, plant and equipment	8,333,762	7,059,412
Other assets	73,883	57,182
Noncurrent assets of discontinued operations	'	750,056
Total assets	9,792,053	8,849,862
Current liabilities:	'	'
Current portion of long-term debt	11,162	23,204
Accounts payable	330,329	276,802
Derivative instruments, at fair value	29,651	75,562
Other current liabilities	152,268	146,605
Liabilities of discontinued operations	'	48,291
Total current liabilities	523,410	570,464
Long-term debt	2,490,354	2,502,969
Deferred income taxes	1,655,765	1,442,071
Other liabilities and credits	258,396	187,941
Noncurrent liabilities of discontinued operations	'	257,615
Total liabilities	4,927,925	4,961,060
Stockholders' equity	'	'
Common stock, no par value, authorized 320,000 shares, shares issued: 175,684 in 2013 and 2012	1,869,843	1,770,545
Treasury stock, shares at cost: 24,800 in 2013 and 25,575 in 2012	-447,738	-461,774
Retained earnings	2,567,980	2,195,502
Accumulated other comprehensive income	44,703	99,547
Total common stockholders' equity	4,034,788	3,603,820
Noncontrolling interests in consolidated subsidiaries	829,340	284,982
Total equity	4,864,128	3,888,802
Total liabilities and equity	$9,792,053	$8,849,862

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
CONSOLIDATED BALANCE SHEETS	'	'
Accounts receivable, accumulated provision for doubtful accounts (in dollars)	$5,171	$5,883
Common stock, par value (in dollars per share)	'	'
Common stock, authorized shares	320,000,000	320,000,000
Common stock, shares issued	175,684,000	175,684,000
Treasury stock, shares	24,800,000	25,575,000

STATEMENTS_OF_CONSOLIDATED_EQU

STATEMENTS OF CONSOLIDATED EQUITY (USD $)	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive (Loss) Income	Noncontrolling Interests in Consolidated Subsidiaries
In Thousands, unless otherwise specified
Balance at Dec. 31, 2010	$3,078,696	$1,244,826	$1,795,766	$38,104	'
Balance (in shares) at Dec. 31, 2010	'	149,153	'	'	'
Increase (Decrease) in Stockholders' Equity	'	'	'	'	'
Net income	479,769	'	479,769	'	'
Net change in cash flow hedges:	'	'	'	'	'
Natural gas, net of tax (benefit) expense of ($50,200), ($61,757)and $110,186 during 2013, 2012 and 2011, respectively	166,840	'	'	166,840	'
Interest rate, net of tax expense (benefit) of $63, $4,833, and ($5,720) during 2013, 2012 and 2011, respectively	-7,433	'	'	-7,433	'
Unrealized gain on available-for-sale securities	-4,896	'	'	-4,896	'
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of $16,115, ($1,992) and ($2,752) during 2013, 2012 and 2011, respectively	-4,474	'	'	-4,474	'
Dividends ($0.12, $0.88 and $0.88 per share during 2013, 2012 and 2011, respectively)	-131,625	'	-131,625	'	'
Stock-based compensation plans, net	16,953	16,953	'	'	'
Stock-based compensation plans, net (in shares)	'	324	'	'	'
Balance at Dec. 31, 2011	3,593,830	1,261,779	2,143,910	188,141	'
Balance (in shares) at Dec. 31, 2011	'	149,477	'	'	'
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 ($50,200), ($61,757)and $110,186 during 2013, 2012 and 2011, respectively	-93,878	'	'	-93,878	'
Interest rate, net of tax expense (benefit) of $63, $4,833, and ($5,720) during 2013, 2012 and 2011, respectively	6,369	'	'	6,369	'
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of $16,115, ($1,992) and ($2,752) during 2013, 2012 and 2011, respectively	-1,085	'	'	-1,085	'
Dividends ($0.12, $0.88 and $0.88 per share during 2013, 2012 and 2011, respectively)	-131,803	'	-131,803	'	'
Stock-based compensation plans, net	41,838	41,621	'	'	217
Stock-based compensation plans, net (in shares)	'	632	'	'	'
Distributions to noncontrolling interests ($1.55 and $0.35 per common unit during 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	'	'	'
Balance at Dec. 31, 2012	3,888,802	1,308,771	2,195,502	99,547	284,982
Balance (in shares) at Dec. 31, 2012	'	150,109	'	'	'
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 ($50,200), ($61,757)and $110,186 during 2013, 2012 and 2011, respectively	-76,489	'	'	-76,489	'
Interest rate, net of tax expense (benefit) of $63, $4,833, and ($5,720) during 2013, 2012 and 2011, respectively	144	'	'	144	'
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of $16,115, ($1,992) and ($2,752) during 2013, 2012 and 2011, respectively	21,501	'	'	21,501	'
Dividends ($0.12, $0.88 and $0.88 per share during 2013, 2012 and 2011, respectively)	-18,094	'	-18,094	'	'
Stock-based compensation plans, net	115,429	114,975	'	'	454
Stock-based compensation plans, net (in shares)	'	775	'	'	'
Distributions to noncontrolling interests ($1.55 and $0.35 per common unit during 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	'	'	'
Balance at Dec. 31, 2013	$4,864,128	$1,422,105	$2,567,980	$44,703	$829,340
Balance (in shares) at Dec. 31, 2013	'	150,884	'	'	'

STATEMENTS_OF_CONSOLIDATED_EQU1

STATEMENTS OF CONSOLIDATED EQUITY (Parenthetical) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
STATEMENTS OF CONSOLIDATED EQUITY	'	'	'
Natural gas, tax (in dollars)	($50,200)	($61,757)	$110,186
Interest rate, tax (in dollars)	63	4,833	-5,720
Pension and other post-retirement benefits liability adjustment, tax (benefit) expense	$16,115	($1,992)	($2,752)
Dividends (in dollars per share)	$0.12	$0.88	$0.88
Distributions to noncontrolling interests (in dollars per common unit)	$1.55	$0.35	'
Common stock, authorized shares	320,000,000	320,000,000	320,000,000
Preferred shares, authorized	3,000,000	3,000,000	3,000,000
Preferred shares issued	0	0	0
Preferred shares outstanding	0	0	0

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
Summary of Significant Accounting Policies	'
	1.                          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. EQT owns a 2.0% general partner interest, all incentive distribution rights and a 42.6% 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. The Company utilizes the equity method of accounting for companies where its ownership is less than or equal to 50% and significant influence exists.
	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 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.
	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, 2013, 2012 and 2011, the Company recorded losses for lower of cost or market adjustments of $0.4 million, $7.0 million and $7.2 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,
		2013				2012
		(Thousands)
	Oil and gas producing properties, successful efforts method	$	8,152,951			$	6,750,343
	Accumulated depletion	(2,134,953		)		(1,572,775		)
	Net oil and gas producing properties	6,017,998				5,177,568
	Midstream plant	2,807,165				2,308,362
	Accumulated depreciation and amortization	(547,991		)		(483,358		)
	Net midstream plant	2,259,174				1,825,004
	Other properties, at cost less accumulated depreciation	56,590				56,840
	Net property, plant and equipment	$	8,333,762			$	7,059,412
	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 $93.5 million, $72.1 million and $69.3 million in 2013, 2012 and 2011, respectively.  The Company capitalized $22.9 million, $15.6 million and $13.3 million of interest relative to Marcellus well development in 2013, 2012 and 2011, 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 oil and gas producing properties consist of gas producing properties which were depleted at an overall average rate of $1.50 per Mcfe, $1.52 per Mcfe and $1.25 per Mcfe produced for the years ended December 31, 2013, 2012 and 2011, 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 risk-adjusted proved and, in some cases, 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.  For the years ended December 31, 2013, 2012 and 2011, the Company did not recognize impairment charges on developed oil and gas properties.
	Capitalized costs of unproved 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.  Undeveloped properties had a net book value of $450.2 million and $385.6 million at December 31, 2013 and 2012, respectively. Undeveloped property impairments primarily as a result of lease expirations prior to drilling of $14.2 million, $5.5 million and $2.6 million are included in exploration expense for the years ended December 31, 2013, 2012 and 2011, respectively.
	At December 31, 2013 and 2012, the Company had no capitalized exploratory well costs.
	Midstream property, plant and equipment is carried at cost.  Depreciation is calculated using the straight-line method based on estimated service lives.  Midstream property consists largely of gathering and transmission systems (25-60 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).
	Major maintenance projects that do not increase the overall life of the related assets are expensed.  When major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.
	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,
		2013			2012			2011
		(Thousands)
	Midstream revenues	$	184,767		$	131,184		$	113,774
	Midstream operating expenses	$	71,517		$	66,202		$	76,247
	The following table presents the regulated net property, plant and equipment included in EQT Midstream:
		As of December 31,
		2013				2012
		(Thousands)
	Property, plant & equipment	$	1,015,118			$	797,405
	Accumulated depreciation and amortization	(158,533		)		(143,714		)
	Net property, plant & equipment	$	856,585			$	653,691
	The regulatory assets associated with deferred taxes of $13.3 million and $18.3 million as of December 31, 2013 and 2012, 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.
	Derivative Instruments:  Derivatives are held as part of a formally documented risk management program.  The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC).  The CRC reports to the Audit Committee of the Board of Directors and is composed of the president and chief executive officer, the chief financial officer and other officers and employees.
	The Company’s risk management program includes the consideration and, when appropriate, the use of (i) exchange-traded natural gas futures contracts and options and over the counter (OTC) natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and (ii) 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 earnings 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.
	For a derivative instrument that has been designated and qualifies as a fair value hedge, the change in the fair value for the instrument is 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) is 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.  Effective October 1, 2013, the Company de-designated all derivative commodity instruments that were previously designated and qualified as fair value hedges.
	Any changes in fair value of derivative instruments that have not been designated as hedges are recognized in the Statements of Consolidated Income each period.
	If a cash flow hedge is terminated or de-designated as a hedge before the settlement date of the hedged item, the amount of accumulated OCI recorded up to that date remains accrued, provided that the forecasted transaction remains 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 which are currently designated as cash flow hedges.
	The Company reports all gains and losses on its energy trading contracts 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 $4.3 million, $3.9 million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, 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 $1.2 million, $6.8 million and $3.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Impairment of Long-Lived Assets:  When events or changes in circumstances indicate that the carrying amount of long-lived assets 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.
	Other Current Liabilities:  Other current liabilities as of December 31, 2013 and 2012 are detailed below.
		December 31,
		2013				2012
		(Thousands)
	Incentive compensation	$	65,053			$	52,291
	Taxes other than income	39,073				37,048
	Accrued interest payable	29,379				29,878
	All other accrued liabilities	18,763				27,388
	Total other current liabilities	$	152,268			$	146,605
Revenue Recognition:  Revenue is recognized for production and gathering activities when deliveries of natural gas, NGLs and crude oil are made. 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.  Revenues associated with energy trading contracts that do not result in physical delivery of an energy commodity are classified as derivative instruments. 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 42.6% 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. 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) 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.  The Company recognizes a loss in the value of an equity method investment that is other than a temporary decline.  The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable.
Purchased Gas Costs:  Purchased gas costs in the Statements of Consolidated Income include natural gas wellhead purchases, natural gas field line purchases, natural gas transmission line purchases, purchased gas cost adjustments, natural gas withdrawn from storage, gas used for product extraction and other gas supply expenses, including pipeline demand charges and transportation costs.
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 on 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,
	2013			2012
	(Thousands)
Asset retirement obligation as of beginning of period	$	109,034		$	102,439
Accretion expense	8,342			7,716
Liabilities incurred	2,510			1,141
Liabilities settled	(3,353		)	-2,408
Revisions in estimated cash flows	(488		)	146
Asset retirement obligation as of end of period	$	116,045		$	109,034
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,
	2013			2012
	(Thousands)
Net unrealized gain from natural gas hedging transactions	$	61,699		$	138,188
Net unrealized loss from interest rate swaps	-1,132			-1,276
Pension and other post-retirement benefits liability adjustment	-15,864			-37,365
Accumulated OCI	$	44,703		$	99,547
Noncontrolling interest: 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.
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, 2013
Discontinued Operations	'
Discontinued Operations	'
	2.                          Discontinued Operations
	On December 17, 2013, the Company and its wholly-owned subsidiary Distribution Holdco, LLC (Holdco) completed the previously announced transactions contemplated by the Master Purchase Agreement, dated as of December 19, 2012 (as amended, the Master Purchase Agreement), by and among the Company, Holdco and PNG Companies LLC (PNG Companies), and the Asset Exchange Agreement, dated as of December 19, 2012 (as amended, the Asset Exchange Agreement), by and between the Company and PNG Companies. PNG Companies is the parent company of Peoples Natural Gas Company LLC. Pursuant to the Master Purchase Agreement and the Asset Exchange Agreement, the Company and Holdco transferred 100% of their ownership interests in Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (Homeworks) to PNG Companies (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.
	As consideration for the Equitable Gas Transaction, the Company received a $740.6 million cash payment, which is subject to certain post-closing adjustments, midstream assets with a preliminary estimated fair value of approximately $141.4 million and other contractual assets with a preliminary estimated fair value of $32.5 million. The contractual assets acquired included a lease of certain physical assets for which the Company will receive $2.5 million per year for 20 years.  This lease is a capital lease under United States GAAP; therefore, the Company recorded a lease receivable, net of unearned interest, of $19.7 million as of December 31, 2013.  Other contractual agreements resulted in intangible assets at the close of the transaction of $12.8 million.  This balance included certain energy marketing contracts valued at $5.0 million which were sold on December 31, 2013 for this amount. The remaining contract-based intangible will be amortized over a 5 year period.
	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,
		2013		2012		2011
		(Thousands)
	Operating revenues	$	332,947	$	314,821	$	420,563
	Income from discontinued operations before income taxes	251,378		81,328		101,010
	Income taxes	159,535		33,835		40,823
	Income from discontinued operations, net of tax	$	91,843	$	47,493	$	60,187
	The Company incurred $8.1 million and $4.5 million of transaction costs related to the Equitable Gas Transaction for the years ended December 31, 2013 and 2012, respectively, which costs are included in the results of discontinued operations for those periods.  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.
	As part of the Equitable Gas Transaction, the Company entered into certain commercial arrangements with PNG Companies and its affiliates that will result in the continuation of transmission and storage service activities between Equitable Gas and Equitrans, L.P. (Equitrans, a subsidiary of the Partnership) for a period of 20 years.  For the years ended December 31, 2013, 2012 and 2011, these intra-entity revenues were $37.6 million, $36.8 million and $37.9 million, respectively.  The Company considered the significance of these amounts compared to total operating revenues of the disposed component and determined that they were not significant.  These amounts are included in revenues for the EQT Midstream segment in continuing operations, and are an expense in arriving at the results of discontinued operations for the years ended December 31, 2013, 2012 and 2011.  This presentation is consistent with how these contracts will be reflected in future periods.
	The following table discloses the major classes of assets and liabilities of discontinued operations included in the Consolidated Balance Sheet:
		As of
		December 31, 2012
		(Thousands)
	Assets
	Accounts receivable and unbilled receivables	$	42,919
	Inventory	31,622
	Other current assets	18,137
	Total current assets	92,678
	Property, plant and equipment, net	655,886
	Regulatory assets	93,599
	Other assets	571
	Total noncurrent assets	750,056
	Assets of discontinued operations	$	842,734
	Liabilities
	Accounts payable	$	12,230
	Accrued customer credits	32,376
	Other current liabilities	3,685
	Total current liabilities	48,291
	Deferred income taxes	223,959
	Pension and other post-retirement benefits	27,985
	Other liabilities	5,671
	Total noncurrent liabilities	257,615
	Liabilities of discontinued operations	$	305,906

EQT_Midstream_Partners_LP

EQT Midstream Partners, LP	12 Months Ended
	Dec. 31, 2013
EQT Midstream Partners, LP	'
EQT Midstream Partners, LP	'
	3.                          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.  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 the contractual arrangements described below.  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.
	Also, in connection with the closing of the IPO:
	·	The Partnership, its general partner and the Company entered into an Omnibus Agreement (Omnibus Agreement), pursuant to which, among other things, the Company agreed to provide the Partnership with general and administrative services and a license to use the name EQT and related marks in connection with the Partnership’s business. The Omnibus Agreement also provides for certain indemnification and reimbursement obligations between the Company and the Partnership.
	·	The Company’s wholly-owned subsidiary, EQT Gathering, LLC (EQT Gathering), and the Partnership entered into an operation and management services agreement (Services Agreement), pursuant to which EQT Gathering provides the Partnership’s pipelines and storage facilities with certain operational and management services. The Services Agreement also provides for certain indemnification and reimbursement obligations between the Partnership and EQT Gathering.
	·	The Partnership entered into a $350 million revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders. 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. The Company is not a guarantor of the Partnership’s obligations under the credit facility.
	·	As a result of the IPO, the Company reversed $5.4 million of net deferred tax liability related to temporary differences between book and tax basis that would no longer impact the Company.
	·	The Company and the Partnership granted certain EQT employees, including executive officers of the Company and the Partnership’s general partner, performance awards representing 146,490 common units of the Partnership. The Company accounted for these awards as equity awards using the grant date fair value. Additionally, the Partnership’s general partner granted each of its independent directors 4,780 phantom units of the Partnership, which units vested upon grant. The value of the phantom units will be paid in common units of the Partnership on the earlier of the director’s death or retirement from 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.
	The Partnership received cash proceeds, net of issuance costs, of approximately $277 million upon the closing of the IPO, which increased the noncontrolling interest component of total equity. Approximately $231 million of the proceeds were distributed to the Company, $12 million was retained by the Partnership to replenish amounts distributed by Equitrans to the Company prior to the IPO, $32 million was retained by the Partnership to pre-fund certain maintenance capital expenditures and $2 million was used by the Partnership to pay credit facility origination fees associated with the credit agreement entered into by the Partnership at the closing of the IPO.
	On July 22, 2013, Sunrise Pipeline, LLC (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). Sunrise continues to be consolidated by the Company as it is still under common control.
	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 includes 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.
	Net income attributable to noncontrolling interests (i.e. the limited partner units not owned by the Company) was $47.2 million and $13.0 million for the years ended December 31, 2013 and 2012, respectively.  The Partnership paid distributions of $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, 2013 and 2012, respectively.

Financial_Information_by_Busin

Financial Information by Business Segment	12 Months Ended
	Dec. 31, 2013
Financial Information by Business Segment	'
Financial Information by Business Segment	'
	4.                          Financial Information by Business Segment
	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. As part of the 2012 budgeting process, the Company allocated additional corporate overhead charges to the operating segments.
	The Company’s management reviews and reports the EQT Production segment results with third-party transportation costs reflected as a deduction from operating revenues. Third-party transportation costs are recorded as a portion of purchased gas costs in the Consolidated Statements of Income.
		Years Ended December 31,
		2013		2012		2011
				(Thousands)
	Revenues from external customers:
	EQT Production	$	1,168,657	$	793,773	$	791,285
	EQT Midstream	614,042		505,498		525,345
	Third-party transportation costs (a)	142,281		126,783		87,034
	Less intersegment revenues, net (b)	-62,969		-48,832		-79,835
	Total	$	1,862,011	$	1,377,222	$	1,323,829
	Operating income:
	EQT Production	$	371,245	$	187,913	$	387,098
	EQT Midstream (c)	328,782		237,324		416,611
	Unallocated expenses (d)	-45,423		-35,608		-42,538
	Total operating income	$	654,604	$	389,629	$	761,171
	Reconciliation of operating income to income from continuing operations:
	Other income	$	9,242	$	15,536	$	33,276
	Interest expense	142,688		184,786		136,328
	Income taxes	175,186		71,461		238,537
	Income from continuing operations	$	345,972	$	148,918	$	419,582
		As of December 31,
		2013		2012
		(Thousands)
	Segment assets:
	EQT Production	$	6,359,065	$	5,675,534
	EQT Midstream	2,514,429		2,046,558
	Total operating segments	8,873,494		7,722,092
	Headquarters assets, including cash and short-term investments	918,559		1,127,770
	Total assets	$	9,792,053	$	8,849,862
	EQT Production and EQT Midstream had segment assets of $5,256.6 million and $1,785.1 million, respectively, as of December 31, 2011.
	(a)         This amount reflects the reclassification of third-party transportation costs from operating revenues to purchased gas 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, $36.8 million and $37.9 million for the years ended December 31, 2013, 2012 and 2011, 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, $11.7 million and $64.5 million for the years ended December 31, 2013, 2012 and 2011, 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)   Gains on dispositions of $19.6 million and $202.9 million are included in EQT Midstream operating income for 2013 and 2011, respectively.  See Note 7.
	(d)  Unallocated expenses consist primarily of incentive compensation, administrative costs and corporate overhead charges previously allocated to the Distribution segment that were reclassified to Headquarters as part of the recast of this Annual Report on Form 10-K to reflect the discontinued operations presentation requirements.
		Years Ended December 31,
		2013		2012		2011
				(Thousands)
	Depreciation, depletion and amortization:
	EQT Production	$	578,641	$	409,628	$	257,144
	EQT Midstream	75,032		64,782		57,135
	Other	-541		207		-411
	Total	$	653,132	$	474,617	$	313,868
	Expenditures for segment assets:
	EQT Production (e)	$	1,423,185	$	991,775	$	1,087,840
	EQT Midstream	369,399		375,731		242,886
	Other	4,292		3,134		4,855
	Total	$	1,796,876	$	1,370,640	$	1,335,581
	(e)          Expenditures for segment assets in the EQT Production segment include $186.2 million, $134.6 million and $57.2 million for property acquisitions in 2013, 2012 and 2011, respectively.  Expenditures for segment assets in the EQT Production segment also include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction, as described in Note 8, in 2011.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Instruments	'
Derivative Instruments	'
	5.                          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 and the storage, marketing and other activities at EQT Midstream. 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 OTC derivative commodity instruments 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 may also engage in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on potential debt issuances.
	The Company 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.
	For a derivative instrument designated and qualified as a fair value hedge, the change in the fair value of 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) is recognized as a portion of operating revenues in the Statements of Consolidated Income. The Company elected to exclude the spot/forward differential for the assessment of effectiveness of the fair value hedges.
	Most of the 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 have been designated and qualify as cash flow hedges. 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,
		2013		2012		2011
				(Thousands)
	Commodity derivatives designated as cash flow hedges
	Amount of gain recognized in OCI (effective portion), net of tax	$	10,669	$	86,259	$	239,019
	Amount of gain reclassified from accumulated OCI, net of tax into operating revenues (effective portion)	87,158		180,137		72,179
	Amount of (loss) recognized in operating revenues (ineffective portion) (a)	-21,335		-75		-181
	Interest rate derivatives designated as cash flow hedges
	Amount of (loss) recognized in OCI (effective portion), net of tax	$	–	$	-7,138	$	-7,573
	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)	-144		-241		-140
	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	$	12,263
	Fair value gain (loss) recognized in operating revenues for inventory designated as hedged item	386		3,292		-6,059
	Derivatives not designated as hedging instruments
	Amount of gain recognized in operating revenues	$	2,834	$	2,176	$	4,209
	(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. For the year ended December 31, 2011, 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 $1.4 million loss due to changes in basis.
		As of December 31,
		2013		2012
		(Thousands)
	Asset derivatives
	Commodity derivatives designated as hedging instruments	$	104,430	$	259,459
	Commodity derivatives not designated as hedging instruments	3,217		44,778
	Total asset derivatives	$	107,647	$	304,237
	Liability derivatives
	Commodity derivatives designated as hedging instruments	$	27,618	$	27,946
	Commodity derivatives not designated as hedging instruments	2,033		47,616
	Total liability derivatives	$	29,651	$	75,562
	During 2011, the Company entered into two forward-starting interest rate swaps to mitigate the risk of rising interest rates.  As of December 31, 2011, one swap had settled and a related loss of $1.4 million, net of tax, was recorded in accumulated OCI, net of tax, to be recognized over the ten year term of the related debt issuance.  The other interest rate swap was in a liability position at December 31, 2011, with $6.2 million included in accumulated OCI, net of tax, on that date.  During 2012, the Company deferred an additional $7.1 million in accumulated OCI, net of tax, related to this 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 strong liquidity position at December 31, 2012.
	The net fair value of derivative commodity instruments changed during 2013 primarily as a result of settlements and increased New York Mercantile Exchange (NYMEX) forward prices.  The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 398 Bcf and 365 Bcf as of December 31, 2013 and 2012, respectively, and are primarily related to natural gas swaps and collars. The open positions at December 31, 2013 had maturities extending through December 2017.  The Company de-designated all derivative commodity instruments that were designated and qualified as fair value hedges effective October 1, 2013.  The absolute quantities of the Company’s derivative commodity instruments that were designated and qualified as fair value hedges totaled 8 Bcf as of December 31, 2012.
	The Company deferred net gains of $61.7 million and $138.2 million in accumulated OCI, net of tax, as of December 31, 2013 and 2012, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges.  Assuming no change in price or new transactions, the Company estimates that approximately $27.2 million of net unrealized gains on its derivative commodity instruments reflected in accumulated OCI, net of tax, as of December 31, 2013 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions. During the year ended December 31, 2012, the Company identified an error related to the accounting for a derivative instrument put premium which should have been recognized over the period January 2010 through December 2011 in conjunction with the settlements of the related financial positions. The Company evaluated materiality in accordance with Securities and Exchange Commission (SEC) Staff Accounting Bulletins Topics 1.M and 1.N and considered relevant qualitative and quantitative factors. Based on this analysis, the Company corrected the error in the second quarter of 2012 through a reduction of EQT Production segment operating revenue by $8.2 million, an increase of accumulated OCI by $5.1 million and a decrease of deferred tax expense by $3.1 million.  The Company concluded that this error was not material to any prior periods, the then expected annual results of 2012 or the trend in earnings over the affected periods. The error had no effect on cash flows or debt covenant compliance.
	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 Futures 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 swap and collar 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, 2013 or December 31, 2012.
	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 $0.3 million and $0.7 million as of December 31, 2013 and December 31, 2012, 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, 2013 and 2012.
	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
	As of December 31, 2012	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	$	304,237	$	-73,753	$	–	$	230,484
Liability derivatives:
Derivative instruments, at fair value	$	75,562	$	-73,753	$	-736	$	1,073
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, 2013, the aggregate fair value of all derivative instruments with credit risk-related contingent features that were in a net liability position was $8.8 million, for which the Company had no collateral posted on December 31, 2013.  If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on December 31, 2013, the Company would not have been required to post additional collateral due to the agreements with the counterparties with which we had the liabilities as of December 31, 2013.  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, 2013.  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, 2013
Fair Value Measurements	'
Fair Value Measurements	'
	6.                          Fair Value Measurements
	The Company records its financial instruments, principally derivative instruments, at fair value in its Consolidated Balance Sheets.  The Company has an established process for determining fair value which is based on 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.  The Company also considers credit default swaps rates where applicable.
	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 include the majority of the Company’s swap agreements. As of December 31, 2012, assets and liabilities in Level 3 included the Company’s collars and a limited number of the Company’s swap 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 and LIBOR-based discount rates.  The Company’s collars are valued using standard industry income approach models and 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 is 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 model include NYMEX forward curves, natural gas volatilities and LIBOR-based discount rates.
	The Company uses NYMEX forward curves to value futures, commodity swaps and collars. The NYMEX forward curves and LIBOR-based discount rates are validated to external sources at least monthly.
	The following assets and liabilities were measured at fair value on a recurring basis during the applicable period:
				Fair value measurements at reporting date using
	Description	December 31,		Quoted		Significant		Significant
		2013		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 at reporting date using
	Description	December 31,		Quoted		Significant		Significant
		2012		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	$	304,237	$	1,228	$	204,592	$	98,417
	Liabilities
	Derivative instruments, at fair value	$	75,562	$	1,609	$	66,250	$	7,703
		Fair value measurements using significant
		unobservable inputs
		(Level 3)
		Derivative instruments, at fair value, net
		Years Ended December 31,
		2013		2012
		(Thousands)
	Balance at January 1	$	90,714	$	143,260
	Total gains or losses:
	Included in earnings	640		-615
	Included in OCI	-2,554		23,386
	Purchases	–		-933
	Settlements	-34,381		-74,384
	Transfers in and/or out of Level 3	-54,419		–
	Balance at December 31	$	–	$	90,714
	There were no material 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 and 2012.
	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 on the Consolidated Balance Sheets at December 31, 2013 and 2012 was approximately $2.8 billion and $2.9 billion, respectively.
	As consideration for the Equitable Gas Transaction, the Company received midstream assets with a preliminary estimated fair value of approximately $141.4 million and other contractual assets with a preliminary estimated 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 value of assets acquired in the Chesapeake acquisition and the fair value of assets related to the defined benefit pension plan assets, see Note 8 and Note 13, respectively.

Sales_of_Properties_and_Contra

Sales of Properties and Contracts	12 Months Ended
	Dec. 31, 2013
Sales of Properties and Contracts	'
Sales of Properties and Contracts	'
	7.                          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 is expected to be collected 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.
	The Company received proceeds of $0.4 million and realized a pre-tax gain of $0.4 million in the year ended December 31, 2013 for the sale of approximately 128 gross acres in Westmoreland County, Pennsylvania.  During the years ended December 31, 2012 and 2011, the Company sold leases relating to approximately 2,900 gross acres in Lycoming County, Pennsylvania. The Company received proceeds of $2.7 million and realized a pre-tax gain of $2.0 million in the year ended December 31, 2012.  The Company received proceeds of $6.0 million and realized a pre-tax gain of $3.9 million in the year ended December 31, 2011. The gains on these dispositions are recorded in other income in the Statements of Consolidated Income.
	On February 1, 2011, the Company sold its natural gas processing complex in Langley, Kentucky and the associated natural gas liquids pipeline (Langley) for $230 million. In conjunction with this transaction, the Company realized a pre-tax gain of $22.8 million.
	On July 1, 2011, the Company sold the Big Sandy Pipeline (Big Sandy) for $390 million.  Big Sandy is a natural gas pipeline regulated by the FERC.  In conjunction with this transaction, the Company realized a pre-tax gain of $180.1 million.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2013
Acquisitions	'
Acquisitions	'
	8.                          Acquisitions
	Chesapeake Energy Corporation Acreage
	On June 3, 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 includes 67,000 Marcellus acres, of which 42,000 acres are 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. The Marcellus wells added approximately 1.7 Bcfe of production sales volumes in 2013 and represented approximately 53.5 Bcfe of proved developed reserves as of the acquisition date.
	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 is a Level 3 measurement.
	Appalachian NPI, LLC
	In December 2000, the Company sold a net profits interest (NPI) in certain producing properties located in the Appalachian Basin to a trust in exchange for approximately $298 million.  The NPI entitled the trust to receive 100% of the net profits received from the sale of natural gas and oil from the producing properties until cumulative production from such properties reached a specified amount.  The Company owned the Class B interest in the trust, entitling it to specified percentages of any available cash from the trust over time.  An unrelated party, Appalachian NPI, LLC (ANPI), owned the Class A interest in the trust.
	Effective May 4, 2011, the Company, through EQT Production Company, acquired the Class A interest in the trust thereby acquiring 100% of the NPI associated with the producing properties (the ANPI transaction).  As part of the consideration for the acquired assets, the Company entered into a discounted natural gas sales agreement with ANPI and assumed a swap held by ANPI on the trust’s sales of natural gas.
	In addition, the Company assumed 7.76% Guaranteed Senior Notes due August 31, 2011 through February 28, 2016 in the aggregate principal amount of $57.1 million. At the time of the transaction, the notes had a fair value of $64.2 million.
	Under United States GAAP, the ANPI transaction was a business combination achieved in stages because the Company owned an equity interest in the trust prior to the transaction.  As required by the relevant accounting standard, the Company revalued its existing equity investment in the trust at fair value on the date of the acquisition and recorded a pre-tax gain of $10.1 million which is included in other income in the Statements of Consolidated Income.  The fair value was determined using an internal model; significant inputs to the calculation included publicly available forward price curves, expected production volumes and operating costs, as well as Company-determined risk adjusted discount rates which were based on publicly available debt and equity risk premiums.
	As a result of this transaction, the Company recorded an increase in oil and gas properties of $140.6 million resulting from the removal of the post-revaluation $48.0 million equity investment in the trust from its books and a net $92.6 million increase in liabilities consisting of: $64.2 million of long-term debt, a $16.4 million discounted sales agreement and a $12.7 million swap liability offset by various working capital balances.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
Income Taxes	'
	9.                          Income Taxes
	Income tax expense (benefit) from continuing operations is summarized as follows:
		Years Ended December 31,
		2013		2012		2011
		(Thousands)
	Current:
	Federal	$	100,796	$	3,771	$	30,837
	State	46,758		229		1,434
	Subtotal	147,554		4,000		32,271
	Deferred:
	Federal	51,767		56,551		177,474
	State	-23,940		11,014		29,003
	Subtotal	27,827		67,565		206,477
	Amortization of deferred investment tax credit	-195		-104		-211
	Total income taxes	$	175,186	$	71,461	$	238,537
	The current income tax expense recorded in 2013 primarily related to federal alternative minimum tax (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 proceeds received relating to the Partnership’s IPO.  The current tax expense recorded in 2011 primarily related to AMT and state taxes due as a result of the Company’s sales of Langley and Big Sandy.
	The American Taxpayer Relief Act of 2012 was enacted on January 2, 2013 and retroactively extended the research and experimentation (R&E) tax credit (with modifications) for 2012 and 2013 and extended 50% bonus depreciation for property placed in service after December 31, 2012 and before January 1, 2014.
	On July 9, 2013, Pennsylvania House Bill 465 was signed into law by the Governor of the Commonwealth of Pennsylvania (the Commonwealth).  This legislation 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, do replace previously issued temporary regulations and are effective for tax years beginning January 1, 2014 with optional adoption in 2013.  The Company elected not to adopt the regulations in 2013, but performed an analysis of the regulations and does not believe that they will have a material impact on its financial statements.
	The Company utilized NOLs for federal tax purposes in 2013, given the aforementioned 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 approximately 83% 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,
		2013		2012		2011
		(Thousands)
	Tax at statutory rate	$	182,406	$	77,133	$	230,342
	State income taxes	16,180		2,869		18,150
	Federal tax credits and incentives	-750		-439		-660
	Permanent basis differences	-407		-2,789		-2,020
	Noncontrolling partners’ share of Partnership earnings	-16,535		-4,571		–
	Other	-5,708		-742		-7,275
	Income tax expense	$	175,186	$	71,461	$	238,537
	Effective tax rate	33.60%		32.40%		36.20%
	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. The overall rate was reduced in both periods as a result of the Company consolidating 100% of the pre-tax income related to the noncontrolling public limited partners’ share of partnership earnings but does not 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, 2012 was 32.4% compared to 36.2% for the year ended December 31, 2011.  The decrease in the rate from 2011 to 2012 was primarily due to a reduction in pre-tax book income on state tax paying entities and a larger shift occurring in 2011 in the Company’s business to states with higher income tax rates.  The overall rate was lower in 2012 as a result of the Company consolidating 100% of the pre-tax income related to the noncontrolling public limited partners’ share of partnership earnings but does not 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):
		2013		2012		2011
		(Thousands)
	Balance at January 1	$	17,858	$	30,730	$	37,943
	Additions based on tax positions related to current year	49,289		2,165		1,245
	Additions for tax positions of prior years	–		2,320		184
	Settlements	–		–		–
	Reductions for tax positions of prior years	-790		-12,235		-7,886
	Lapse of statute of limitations	-9,270		-5,122		-756
	Balance at December 31	$	57,087	$	17,858	$	30,730
	Included in the tabular reconciliation above at December 31, 2013, 2012 and 2011 are $7.6 million, $6.4 million and $15.9 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 $9.8 million and $14.6 million for the years ended December 31, 2013 and 2012, 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 reversed approximately $0.5 million, $1.8 million and $9.7 million of previously recorded interest expense in 2013, 2012 and 2011, respectively.  Interest and penalties of $0.2 million, $0.5 million and $2.3 million were included in the balance sheet reserve at December 31, 2013, 2012 and 2011, respectively.
	There were no material changes to the Company’s methodology for unrecognized tax benefits during 2013. The total amount of unrecognized tax benefits (excluding interest and penalties) that, if recognized, would affect the effective tax rate was $33.3 million, $5.3 million and $5.2 million as of December 31, 2013, 2012 and 2011, respectively.
	Decreases to the unrecognized tax benefits during 2013, 2012, and 2011 were primarily attributable to the reversal of certain prior year tax positions related to state taxes and the related interest expense as well as the lapse of applicable statutes of limitations. As of December 31, 2013, 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 through 2009 and the 2010 and 2011 tax years are currently under examination. The Company also is the subject of various state income tax examinations.  The Company believes that it is appropriately reserved for uncertain tax positions.
	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,
		2013		2012
		(Thousands)
	Deferred income taxes:
	Total deferred income tax assets .	$	-670,368	$	-696,252
	Total deferred income tax liabilities	2,295,128		2,122,377
	Total net deferred income tax liabilities	1,624,760		1,426,125
	Total deferred income tax liabilities (assets)
	Drilling and development costs expensed for income tax reporting	1,181,375		933,800
	Tax depreciation in excess of book depreciation	923,443		924,229
	Investment in Partnership	101,569		108,764
	Accumulated OCI	28,597		81,087
	Post-retirement benefits	-3,946		-3,784
Incentive compensation	-60,982		-28,811
Alternative minimum tax credit carryforward	-246,157		-69,901
Net operating loss carryforwards	-359,283		-593,756
Other	3,740		8,261
Total excluding valuation allowances	1,568,356		1,359,889
Valuation allowance	56,404		66,236
Total (including amounts classified as current assets of $31,005 and $15,946, respectively)	$	1,624,760	$	1,426,125
The net deferred tax liability relating to the Company’s accumulated OCI balance as of December 31, 2013 consisted of a $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 net deferred tax liability relating to the Company’s accumulated OCI balance as of December 31, 2012 consisted of an $88.8 million deferred tax liability related to the Company’s net unrealized gain from hedging transactions, a $3.6 million deferred tax asset related to other post-retirement benefits, and a $4.1 million deferred tax asset related to the Company’s pension plans.
The Company also has a total deferred tax asset of $183.2 million at December 31, 2013 related to the federal NOL carryforward from 2012 of $166.1 million and 2011 of $17.1 million, respectively.  The deferred tax asset has been increased for uncertain tax positions of approximately $10.6 million as of December 31, 2013, and reduced for approximately $3.7 million as of December 31, 2012. The federal NOL carryforward period is 20 years and, if unused, the loss carryforward, in excess of the 2013 NOL utilization, for 2012 and 2011 will expire in 2032 and 2031, 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, 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.  As of December 31, 2012, the Company had a deferred tax asset of $86.0 million, net of valuation allowances of $66.2 million, related to tax benefits from state NOL carryforwards with various expiration dates ranging from 2013 to 2032.  The deferred tax asset has been reduced for uncertain tax positions of approximately $0.5 million during the years ended December 31, 2013 and 2012, respectively.
During the years ended December 31, 2012 and 2011, share-based payment arrangements paid in stock generated an $8.1 million and $6.6 million excess tax benefit, respectively, which was not recorded in the financial statements as an addition to common stockholders’ equity due to the Company’s NOL position.  Due to taxable income generated in the year ended December 31, 2013, the Company has recorded tax benefits of $12.2 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 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, 2013
Equity in Nonconsolidated Investments	'
Equity in Nonconsolidated Investments	'
	10.                   Equity in Nonconsolidated Investments
	The Company has ownership interests in nonconsolidated investments that are accounted for under the equity method of accounting.  The following table summarizes the Company’s equity in the nonconsolidated investments:
				Interest		Ownership	As of December 31,
						as of
						December
	Investees	Location		Type		31, 2013	2013		2012
							(Thousands)
	Nora Gathering, LLC (Nora LLC)	USA		Joint		50%	$	128,983	$	130,368
	The Company’s ownership share of the earnings for 2013, 2012 and 2011 related to the total investments accounted for under the equity method was $7.6 million, $6.1 million and $7.2 million, respectively, reported in other income on the Statements of Consolidated Income.  Also included in its ownership share of the earnings of equity method investments for the year ended December 31, 2011 was the Company’s equity earnings related to its equity investment in Appalachian Natural Gas Trust (ANGT), which no longer exists due to the ANPI transaction.  See Note 8 for further details.
	EQT Midstream’s equity investment in Nora LLC represents a 50% ownership interest which was obtained during 2007 through a series of transactions with Pine Mountain Oil and Gas, Inc., a subsidiary of Range Resources Corporation, by contributing Nora area gathering property in exchange for the ownership interest.  EQT Midstream made no additional equity investments in Nora LLC during 2012 or 2013.
	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,
		2013			2012
		(Thousands)
	Current assets	$	27,014		$	15,966
	Noncurrent assets	239,583			249,347
	Total assets	$	266,597		$	265,313
	Current liabilities	$	8,529		$	4,476
	Stockholders’ equity	258,068			260,837
	Total liabilities and stockholders’ equity	$	266,597		$	265,313
	Summarized Statements of Income
		Years Ended December 31,
		2013			2012		2011
		(Thousands)
	Revenues	$	45,040		$	47,888	$	49,772
	Operating expenses	29,810			35,596		35,520
	Net income	$	15,230		$	12,292	$	14,252

ShortTerm_Loans

Short-Term Loans	12 Months Ended
	Dec. 31, 2013
Short-Term Loans	'
Short-Term Loans	'
	11.                   Short-Term Loans
	As of December 31, 2013, the Company had a $1.5 billion revolving credit facility that expires on December 8, 2016. The Company may request two one-year extensions of the expiration date 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 16 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.
	As of December 31, 2013, the Partnership had a $350 million revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders, which will expire on July 2, 2017. 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. 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.
	As of December 31, 2013 and 2012, neither the Company nor the Partnership had loans or letters of credit outstanding under their respective revolving credit facilities. Commitment fees averaging approximately 24 basis points for the year ended December 31, 2013 and 25 basis points for the year ended December 31, 2012 were incurred to maintain credit availability under the Company’s revolving credit facility. The Partnership incurred commitment fees averaging approximately 25 basis points for the years ended December 31, 2013 and 2012 to maintain credit availability under its revolving credit facility.
	The maximum amount of outstanding short-term loans at any time under the Company’s credit facility during the years ended December 31, 2013 and 2011 was $178.5 million and $104.0 million, respectively.  The Company did not have any short-term loans outstanding at any time during the year ended December 31, 2012.  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 1.67%. The average daily balance of short-term loans outstanding for the Company during the year ended December 31, 2011 was approximately $5.5 million at a weighted average annual interest rate of 1.81%.  The Partnership had no short-term loans outstanding at any time during the years ended December 31, 2013 or 2012.
	The Company’s debt agreements and other financial obligations contain various provisions that, if not complied with, could result in termination of the agreements, require early payment of amounts outstanding or similar actions.  The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions.  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, 2013, 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 the termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the credit facility related to maintenance of permitted leverage coverage and interest coverage ratios, limitations on transactions with affiliates, insolvency events, nonpayment of schedule principal or interest payments, acceleration of 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, after the Partnership obtains an investment grade rating, not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and, until the Partnership obtains an investment grade rating, a consolidated interest coverage ratio of not less than 3.00 to 1.00.  As of December 31, 2013, the Partnership was in compliance with all credit facility provisions and covenants.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-Term Debt	'
Long-Term Debt	'
	12.                   Long-Term Debt
		As of December 31,
		2013		2012
		(Thousands)
	7.76% notes, due 2014 thru 2016	$	18,316	$	32,973
	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
	7.75% debentures, due July 15, 2026	115,000		115,000
	Medium-term notes:
	8.7% to 9.0% Series A, due 2014 thru 2021	40,200		40,200
	7.3% to 7.6% Series B, due 2015 thru 2023	20,000		30,000
	7.6% Series C, due 2018	8,000		8,000
		2,501,516		2,526,173
	Less debt payable within one year	11,162		23,204
	Total long-term debt	$	2,490,354	$	2,502,969
	The indentures and other agreements governing the Company’s 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 debt rating would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.
	Aggregate maturities of long-term debt are $11.2 million in 2014, $166.0 million in 2015, $3.0 million in 2016, zero in 2017 and $708.0 million in 2018.

Pension_and_Other_PostRetireme

Pension and Other Post-Retirement Benefit Plans	12 Months Ended
	Dec. 31, 2013
Pension and Other Post-Retirement Benefit Plans	'
Pension and Other Post-Retirement Benefit Plans	'
	13.                   Pension and Other Post-Retirement Benefit Plans
	The following table sets forth the defined benefit pension and other post-retirement benefit plans’ funded status and amounts recognized for those plans in the Company’s Consolidated Balance Sheets.  Refer to Note 2 for further information related to the Equitable Gas Transaction.
		For the Years Ended December 31,
		2013				2012				2013			2012
		Pension Benefits								Other Benefits
		(Thousands)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	63,270			$	61,885			$	36,255		$	35,293
	Service cost	500				500				905			737
	Interest cost	1,935				2,448				1,110			1,427
	Amendments	–				(126		)		–			–
	Actuarial loss	(3,038		)		5,733				(2,355		)	2,656
	Benefits paid	(5,269		)		(5,571		)		(3,961		)	(3,858		)
	Expenses paid	(493		)		(511		)		–			–
	Divestitures	(34,410		)		–				(13,701		)	–
	Settlements	(667		)		(1,088		)		–			–
	Subtotal	21,828				63,270				18,253			36,255
	Benefit obligation included in discontinued operations	–				42,835				–			15,577
	Benefit obligation at end of year	$	21,828			$	20,435			$	18,253		$	20,678
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	46,984			$	45,951			$	165		$	19
	Actual gain on plan assets	7,304				5,346				–			–
	Contributions	2,639				2,857				328			146
	Benefits paid	(5,269		)		(5,571		)		–			–
	Expenses paid	(493		)		(511		)		–			–
	Divestitures	(30,409		)		–				–			–
	Settlements	(667		)		(1,088		)		–			–
	Subtotal	20,089				46,984				493			165
	Fair value of plan assets included in discontinued operations	–				30,428				–			–
	Fair value of plan assets at end of year	20,089				16,556				493			165
	Funded status at end of year	$	(1,739	)		$	(3,879	)		$	(17,760	)	$	(20,513	)
	Amounts recognized in the statement of financial position consist of:
	Current liabilities	$	–			$	–			$	(1,341	)	$	(3,353	)
	Noncurrent liabilities	(1,739		)		(3,879		)		(16,419		)	(17,160		)
	Net amounts recognized	$	(1,739	)		$	(3,879	)		$	(17,760	)	$	(20,513	)
	Amounts recognized in accumulated OCI, net of tax, consist of:
	Net loss	$	7,524			$	24,634			$	8,234		$	14,291
	Net prior service (credit)	–				–				106			(1,560		)
	Net amount recognized	$	7,524			$	24,634			$	8,340		$	12,731
	The accumulated benefit obligation for the Company’s defined benefit pension plans was $21.8 million and $20.4 million at December 31, 2013 and 2012, 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,
		2013				2012				2011			2013				2012			2011
		Pension Benefits											Other Benefits
		(Thousands)
	Components of net periodic benefit cost:
	Service cost	$	500			$	500			$	500		$	905			$	737		$	620
	Interest cost	1,935				2,448				3,115			1,110				1,427			1,771
	Expected return on plan assets	(3,323		)		(3,712		)		(4,070		)	–				–			–
	Amortization of prior service cost	–				–				–			(845		)		(845		)	(902		)
	Recognized net actuarial loss	2,306				1,880				1,471			1,760				1,671			1,605
	Settlement loss and special termination benefits	381				725				530			–				–			–
	Subtotal	1,799				1,841				1,546			2,930				2,990			3,094
	Net periodic benefit cost of discontinued operations	1,552				1,586				1,387			1,356				1,288			1,427
	Net periodic benefit cost	$	247			$	255			$	159		$	1,574			$	1,702		$	1,667
	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 Midstream business.
		For the Years Ended December 31,
		2013				2012				2011			2013				2012			2011
		Pension Benefits											Other Benefits
		(Thousands)
	Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
	Net (gain) loss	$	712			$	261			$	3,378		$	2,147			$	494		$	181
	Net prior service cost	–				–				–			416				330			915
Total recognized in OCI, net of tax	$	712			$	261			$	3,378		$	2,563			$	824		$	1,096
Total recognized in net periodic benefit cost and OCI, net of tax	$	959			$	2,102			$	4,924		$	4,137			$	3,814		$	4,190
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 2014 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 2014 are $0.4 million and $(0.3 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,
	2013		2012		2013		2012
	Pension Benefits				Other Benefits
Discount rate	4.00%		3.25%		4.00%		3.25%
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,
	2013			2012			2013			2012
	Pension Benefits						Other Benefits
Discount rate	3.25%			4.25%			3.25%			4.25%
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 forecasted rates of return on the types of securities held.  The Company considered the historical rates of return earned on plan assets, an expected return percentage by asset class based upon a survey of investment managers and the Company’s actual and targeted investment mix.  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 determined as of January 1, 2014 is 7.75%.  This assumption will be used to derive the Company’s 2014 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 is changed.
For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2013 was 7.00% for both the Pre-65 and Post-65 medical charges.  The rates were assumed to decrease gradually to ultimate rates of 5.00% in 2018.
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
	2013			2012			2011			2013		2012			2011
	(Thousands)
Increase (decrease) to total of service and interest cost components	$	25		$	32		$	40		$	-26	$	-32		$	-39
Increase (decrease) to post-retirement benefit obligation	$	220		$	711		$	730		$	-223	$	-688		$	-702
The Company’s pension asset allocation at December 31, 2013 and 2012 and target allocation for 2014 by asset category are as follows:
			Percentage of Plan Assets
	Target		at December 31,
Asset Category	Allocation 2014		2013			2012
Domestic broadly diversified equity securities	40% - 60%		42	%		53	%
Fixed income securities	20% - 50%		29	%		32	%
International broadly diversified equity securities	5% - 15%		7	%		10	%
Alternative fixed income securities	0% - 10%		4	%		4	%
Cash and equivalent investments	0% - 15%		18	%		1	%
			100	%		100	%
The investment activities of the Company’s pension 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.  The BIC has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines.  The investment goals of the BIC are to minimize high levels of risk at the total pension investment fund level.  The BIC monitors the asset allocation on a quarterly basis and adjustments are made, as needed, to rebalance the assets within the prescribed target ranges.  Comparative market and peer group benchmarks are utilized to ensure that each of the firm’s investment managers is performing satisfactorily.
The cash and equivalent investments category is outside of the target allocation as a result of liquidating investments for transfer to the Peoples Natural Gas Company LLC DB Plan for Former Employees of Equitable Gas Company based upon a preliminary asset allocation calculation in connection with the Equitable Gas Transaction.  The excess cash investment balance is temporary and a portion will be re-invested in other assets in the first quarter of 2014, which will realign the investment balances with the target allocation.
The Company made cash contributions of approximately $2.6 million, $2.9 million and $4.3 million to its pension plan during 2013, 2012 and 2011, respectively, to meet certain funding targets. The Company expects to make cash payments of at least $0.4 million related to its pensions during 2014, which will meet minimum required contributions and the 80% funding obligation on the pension plan.  Pension plan cash contributions are designed to at least meet requirements of the 80% funding level.  The dollar amount of a 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 these variations to have a significant effect on its financial position, results of operations or liquidity.
The following pension benefit payments, which reflect expected future service, are expected to be paid by the plan during each of the next five years and the five years thereafter: $2.5 million in 2014; $2.2 million in 2015; $2.0 million in 2016; $1.8 million in 2017; $1.9 million in 2018; and $8.4 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: $1.9 million in 2014; $1.8 million in 2015; $1.8 million in 2016; $1.7 million in 2017; $1.7 million in 2018; and $7.7 million in the five years thereafter.
Expense recognized by the Company related to its defined contribution plans totaled $14.6 million in 2013, $12.0 million in 2012 and $10.1 million in 2011.
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 $6.9 million and $8.8 million as of December 31, 2013 and 2012, 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 $13.2 million and $38.2 million as of December 31, 2013 and 2012, respectively.  These investments are valued at current market value of the underlying assets of the fund and therefore are considered Level 2.
Assets classified as Level 1 transferred to Level 2 during the year ended December 31, 2012 were $9.8 million due to the plan severing its investment in a bond mutual fund and investing in a bond portfolio.  This change provided the ability to manage these investments by individual performance.  There were no changes in risk, exposure or asset allocation.
As of December 31, 2013 and 2012, the defined benefit 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, 2013
Changes in Accumulated Other Comprehensive Income by Component	'
Changes in Accumulated Other Comprehensive Income by Component	'
	14.                   Changes in Accumulated Other Comprehensive Income by Component
	The following tables explain the changes in accumulated OCI by component for the year ended December 31, 2013:
		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
	Amounts reclassified from accumulated OCI into realized (income) expense, 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, 2013
Common Stock and Earnings Per Share	'
Common Stock and Earnings Per Share	'
	15.                   Common Stock and Earnings Per Share
	Common Stock
	At December 31, 2013, shares of EQT’s authorized and unissued common stock were reserved as follows:
		(Thousands)
	Possible future acquisitions	20,457
	Stock compensation plans	8,911
	Total	29,368
	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,
		2013		2012		2011
		(Thousands except per share amounts)
	Basic earnings per common share:
	Net income attributable to EQT Corporation	$	390,572	$	183,395	$	479,769
	Average common shares outstanding	150,574		149,619		149,392
	Basic earnings per common share	$	2.59	$	1.23	$	3.21
	Diluted earnings per common share:
	Net income attributable to EQT Corporation	$	390,572	$	183,395	$	479,769
	Average common shares outstanding	150,574		149,619		149,392
	Potentially dilutive securities:
	Stock options and awards (a)	1,213		887		817
	Total	151,787		150,506		150,209
	Diluted earnings per common share	$	2.57	$	1.22	$	3.19
	(a)         There were no options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive for the year ended December 31, 2013. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 281,528 and 6,480 shares for the year ended December 31, 2012 and 2011, respectively.
	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, 2013

Share-Based Compensation Plans

'

Share-Based Compensation Plans

'

16.                   Share-Based Compensation Plans

Share-based compensation expense recorded by the Company was as follows:

Years Ended December 31,

2013

2012

2011

(Thousands)

2008 Executive Performance Incentive Program

$

–

$

–

$

923

2010 Executive Performance Incentive Programs

–

1,940

2,118

2012 Executive Performance Incentive Program

6,739

10,633

–

2013 Executive Performance Incentive Program

6,602

–

–

2007 Supply Long-Term Incentive Program

–

–

198

2010 Stock Incentive Award Program

–

4,022

4,241

2011 EQT Value Driver Award Program

–

3,033

15,807

2012 EQT Value Driver Award Program

2,327

11,557

–

2013 EQT Value Driver Award Program

13,050

–

–

2011 Volume and Efficiency Program

13,834

5,286

5,384

Restricted stock awards

3,033

2,007

1,929

Non-qualified stock options

3,805

3,580

6,057

Non-employee directors’ share-based awards

7,432

2,558

3,320

EQM Total Return Program

837

419

–

EQM non-employee directors’ share-based awards

144

116

–

Expense attributable to discontinued operations

741

670

352

Total share-based compensation expense

$

58,544

$

45,821

$

40,329

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, 2013, 2012 and 2011 were $32.9 million, $7.9 million and $3.1 million, respectively.  During the years ended December 31, 2013, 2012 and 2011, share-based payment arrangements paid in stock generated tax benefits of $14.4 million, $15.1 million and $8.1 million, respectively. As a result of the Company’s NOL position in 2012 and 2011, excess tax benefits of $8.1 million and $6.6 million, respectively, were not recorded in the financial statements as an addition to common stockholders’ equity.  For share-based payment arrangements paid in cash, the Company recognizes tax benefits at the effective tax rate, except as limited by Section 162(m) of the Internal Revenue Code.

Executive Performance Incentive Programs

In 2008, the Compensation Committee of the Board of Directors adopted the 2008 Executive Performance Incentive Program (2008 EPIP) under the 1999 Long-Term Incentive Plan.  The 2008 EPIP was established to provide long-term incentive opportunities to key executives to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. The vesting of the stock units granted under the 2008 EPIP occurred on December 31, 2011, after the ordinary close of the performance period.  The vesting resulted in approximately 44,400 units (75% of the award) with a value of approximately $2.5 million being distributed in cash on December 31, 2011.  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.  The 2008 EPIP expense was classified as selling, general and administrative expense in the Statements of Consolidated Income.

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 interests 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 30, 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, 115,590 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.

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.  A total of 351,480 units were outstanding at January 1, 2013.  Adjusting for 16,425 forfeitures, there were 335,055 outstanding units as of December 31, 2013. The vesting of the units under the 2012 EPIP will occur upon payment after December 31, 2014 (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, 2012 through December 31, 2014. 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 Accounting Standards Codification (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 probable outcome at each reporting period, in order to record expense at the then-probable outcome grant date fair value. As of December 31, 2013, the compensation expense was recorded using a grant date fair value of $123.37, which was the grant date fair value computed for the outcome which management estimated to be most probable.  The total compensation cost capitalized in 2013 and 2012 was $8.1 million and $2.1 million, respectively.  As of December 31, 2013, $13.8 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2012 EPIP was expected to be recognized by December 31, 2014.

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.

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 314,280 units were granted in 2013 and no additional units may be granted. Adjusting for 16,683 forfeitures, there were 297,597 outstanding units as of December 31, 2013. 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, 2013, the compensation expense was recorded using a grant date fair value of $126.45 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 2013 was $5.0 million.  As of December 31, 2013, $23.2 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2013 EPIP was expected to be recognized over the next two years.

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.

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 driver 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 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 objectives 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 driver performance over the period January 1, 2011 through December 31, 2011.  The two tranches of awards vested and were distributed in cash payouts 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.  As of January 1, 2013, 409,357 awards including accrued dividends were outstanding under the 2012 EQT VDA.  The first tranche of the confirmed awards vested and 204,679 awards were distributed in Company common stock in January 2013.  The remainder of the confirmed awards vested and were paid in Company common stock in February 2014. As of December 31, 2013, 196,609 awards including accrued dividends were outstanding under the 2012 EQT VDA. The Company accounts 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 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 $2.6 million and $5.0 million in 2013 and 2012, respectively.

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 December 31, 2013, 614,048 awards including accrued dividends were outstanding under the 2013 EQT VDA.  The first tranche of the confirmed awards vested and were distributed in Company common stock in February 2014.  The remainder of the confirmed awards is expected to vest and be paid in Company common stock in the first quarter of 2015.  The Company accounts for these awards as equity awards using the $58.98 grant date fair value per unit which was equal to the Company’s common stock price on the date prior to the date of grant.  Due to the graded vesting of the award, the Company 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 2013 was $14.1 million.  As of December 31, 2013, $9.0 million of unrecognized compensation cost related to the 2013 EQT VDA was expected to be fully recognized by 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 payout opportunity with respect to the target awards is anticipated to be 300% of the outstanding units based on the achievement of predetermined specified performance measures.  Payment of the awards will be distributed in Company common stock during the first quarter 2014 after the end of the performance period on December 31, 2013.  The Company accounts 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.  As of January 1, 2013, 228,640 awards were outstanding. Adjusting for forfeitures of 7,500, there were 221,140 awards outstanding as of December 31, 2013, not including an adjustment for the performance multiplier.  The total compensation cost capitalized was $2.8 million, $2.5 million and $1.9 million in 2013, 2012 and 2011, respectively.  As of December 31, 2013, compensation expense related to the 2011 VEP has been fully recognized.

Restricted Stock Awards

The Company granted 101,510, 103,730 and 65,390 restricted stock awards during the years ended December 31, 2013, 2012 and 2011, 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 $71, $54 and $52 for the years ended December 31, 2013, 2012 and 2011, respectively.  The total fair value of restricted stock awards vested during the years ended December 31, 2013, 2012 and 2011 was $4.3 million, $1.6 million and $5.1 million, respectively.

As of December 31, 2013, $7.0 million of unrecognized compensation cost related to nonvested restricted stock awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.7 years.

A summary of restricted stock activity as of December 31, 2013, 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, 2013

204,118

$

49.86

$

10,176,930

Granted

101,510

$

70.59

7,166,006

Vested

(91,478

)

$

46.87

(4,287,701

)

Forfeited

(31,772

)

$

55.15

(1,752,243

)

Outstanding at December 31, 2013

182,378

$

61.98

$

11,302,992

For the restricted stock awards that vested in 2013, 23,053 related to discontinued operations at a weighted average fair value of $56.28 and an aggregate fair value of $1.3 million. For the restricted stock awards that were forfeited in 2013, 18,357 related to discontinued operations at a weighted average fair value of $55.00 and an aggregate fair value of $1.0 million.

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, 2013, 2012 and 2011.  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,

2013

2012

2011

Risk-free interest rate

0.76%

0.89%

2.02%

Dividend yield

0.22%

1.64%

2.19%

Volatility factor

31.69%

31.44%

28.92%

Expected term

5 years

5 years

5 years

The Company granted 259,600, 278,300 and 229,100 stock options during the years ended December 31, 2013, 2012 and 2011, respectively.   The weighted average grant date fair value of the options was $16.72, $13.19 and $10.06 for the years ended December 31, 2013, 2012 and 2011, respectively.  The total intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $22.8 million, $11.8 million, and $18.3 million, respectively.

As of December 31, 2013, $2.1 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2014.

A summary of option activity as of December 31, 2013, 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, 2013

1,864,375

$   46.01

Granted

259,600

$   58.98

Exercised

-637,174

$   42.44

Forfeited

-4,800

$   58.98

Outstanding at December 31, 2013

1,482,001

$   49.77

4.7 years

$ 59,287,589

Exercisable at December 31, 2013

1,088,051

$   46.98

3.3 years

$ 46,570,891

For stock options exercised in 2013, 8,100 shares related to discontinued operations at a weighted average exercise price of $24.39.

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 179,639 non-employee director share-based awards including accrued dividends were outstanding as of December 31, 2013.  A total of 25,500, 28,140 and 22,140 share-based awards were granted to non-employee directors during the years ended December 31, 2013, 2012 and 2011, respectively.  The weighted average fair value of these grants, based on the Company’s common stock price on the grant date, was $58.98, $53.47 and $44.84 for the years ended December 31, 2013, 2012 and 2011, respectively.

EQM Awards

At the closing of the Partnership’s IPO in July 2012, the Company 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%.  Adjusting for 3,990 forfeitures, there were 142,500 awards outstanding as of December 31, 2013. As of December 31, 2013, $1.7 million of unrecognized compensation cost related to the EQM Total Return Program was expected to be recognized over the next two years.

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 8,886 independent director unit-based awards including accrued distributions were outstanding as of December 31, 2013.  A total of 3,790 and 4,780 unit-based awards were granted to independent directors during the years ended December 31, 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 $37.92 and $24.30 for the years ended December 31, 2013 and 2012, respectively.

2014 Value Driver Award Programs and 2014 Executive Performance Incentive Program

Effective in 2014, the Compensation Committee of the Board of Directors adopted the 2014 EQT Value Driver Award Program (2014 EQT VDA), the 2014 EQM Value Driver Program (2014 EQM VDA) and the 2014 Executive Performance Incentive Program (2014 EPIP) under the 2009 Long-Term Incentive Plan. The 2014 EQT VDA, 2014 EQM VDA and 2014 EPIP were established to align the interests of key employees with the interests of shareholders, Partnership unitholders and customers and the strategic objectives of the Company and the Partnership.

A total of 187,160 units were granted under the 2014 EQT VDA.  Fifty percent of the units confirmed under the 2014 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 2014 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 2014 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, 2014 through December 31, 2014.  If earned, the 2014 EQT VDA units are expected to be paid in cash. The Company did not record any obligation or expense related to the 2014 EQT VDA as of December 31, 2013.

A total of 32,840 units were granted under the 2014 EQM VDA.  Fifty percent of the units confirmed under the 2014 EQM VDA will vest upon the payment date following the first anniversary of the grant date; the remaining 50% of the confirmed units under the 2014 EQM 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 2014 Partnership EBITDA performance as compared to the Partnership’s annual business plan and individual, business unit and Partnership value driver performance over the period January 1, 2014 through December 31, 2014.  If earned, the 2014 EQM VDA units are expected to be paid in Partnership common units. The Company did not record any expense related to the 2014 EQM VDA as of December 31, 2013.

A total of 278,430 units were granted under the 2014 EPIP.  The vesting of the units under the 2014 EPIP will occur upon payment after December 31, 2016 (the end of the three-year performance period).  The payout will vary between zero and 300% of the number of outstanding units contingent upon a combination of the level of total shareholder return relative to a predefined peer group and the level of production sales volume growth over the period January 1, 2014 through December 31, 2016.  If earned, the 2014 EPIP units are expected to be distributed in Company common stock.  The Company did not record any expense related to the 2014 EPIP as of December 31, 2013.

2014 Stock Options

Effective January 1, 2014, the Compensation Committee of the Board of Directors granted 133,500 non-qualified stock options to key employees of the Company.  The 2014 options are ten-year options, with an exercise price of $89.78 and are subject to three year cliff vesting. The Company did not record any expense related to 2014 stock options as of December 31, 2013.

Concentrations_of_Credit_Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2013
Concentrations of Credit Risk	'
Concentrations of Credit Risk	'
	17.                   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 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 11% of its revenues in 2013. No single customer accounted for more than 10% of revenues in 2012 or 2011.
	Approximately 82% of the Company’s accounts receivable balance as of December 31, 2013 and 2012, 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, 2013, 2012 or 2011.
	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, 2013, 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, 2013
Commitments and Contingencies	'
Commitments and Contingencies	'
	18.                   Commitments and Contingencies
	The Company has commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines.  Future payments for these items as of December 31, 2013 totaled $2,167.8 million (2014 - $140.8 million, 2015 - $192.4 million, 2016 - $184.8 million, 2017 - $180.8 million, 2018 - $180.8 million and thereafter - $1,288.2 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 $70.4 million as of December 31, 2013.  Operating lease rentals for drilling contractors, office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $56.0 million in 2013, $45.0 million in 2012 and $74.7 million in 2011.  Future lease payments under non-cancelable operating leases as of December 31, 2013 totaled $134.2 million (2014 - $42.9 million, 2015 - $25.6 million, 2016 - $18.4 million, 2017 – $10.7 million, 2018 - $6.3 million and thereafter - $30.3 million).
	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 $0.6 million is included in other liabilities and credits in the Consolidated Balance Sheets as of December 31, 2013.
	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, 2013
Guarantees	'
Guarantees	'
	19.                   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 $172 million as of December 31, 2013, extending at a decreasing amount for approximately 14 years.
	In exchange for the Company’s agreement to maintain these guarantee obligations, the purchaser of the NORESCO business and NORESCO agreed, among other things, that NORESCO would fully perform its obligations under each underlying agreement and agreed to reimburse the Company for any loss under the guarantee obligations, provided that the purchaser’s reimbursement obligation will not exceed $6 million in the aggregate and will expire on November 18, 2014.  In 2008, the original purchaser of NORESCO sold its interest in NORESCO and transferred its obligations to a third party.  In connection with that event, the new owner delivered to the Company a $1 million letter of credit supporting its obligations.
	The NORESCO 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, 2013
Interim Financial Information (Unaudited)	'
Interim Financial Information (Unaudited)	'
	20.      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)
	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
	2012 (a)
	Operating revenues	$	334,291	$	298,742	$	337,916	$	406,273
	Operating income	111,054		70,817		81,253		126,505
	Amounts attributable to EQT Corporation:
	Income from continuing operations	48,467		25,302		29,010		33,123
	Income from discontinued operations	23,568		6,144		2,863		14,918
	Net income attributable to EQT Corporation	$	72,035	$	31,446	$	31,873	$	48,041
	Earnings per share of common stock attributable to EQT Corporation:
	Basic:
	Income from continuing operations	$	0.32	$	0.17	$	0.19	$	0.22
	Income from discontinued operations	0.16		0.04		0.02		0.1
	Net income	$	0.48	$	0.21	$	0.21	$	0.32
	Diluted:
	Income from continuing operations	$	0.32	$	0.17	$	0.19	$	0.22
	Income from discontinued operations	0.16		0.04		0.02		0.1
	Net income	$	0.48	$	0.21	$	0.21	$	0.32
	(a)                     The sum of the quarterly data in some cases may not equal the yearly total due to rounding.
	Differences between all amounts in the above table and those previously reported in the Company’s 2013 and 2012 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, 2013
Natural Gas Producing Activities (Unaudited)	'
Natural Gas Producing Activities (Unaudited)	'
	21.          Natural Gas Producing Activities (Unaudited)
	The supplementary information summarized below presents the results of natural gas and oil activities for the EQT Production segment in accordance with the successful efforts method of accounting for production activities.
	Production Costs
	The following table presents the costs incurred relating to natural gas, NGL and oil production activities (a):
			For the Years Ended December 31,
			2013			2012			2011
			(Thousands)
	At December 31:
	Capitalized costs		$	8,152,951		$	6,750,343		$	5,772,083
	Accumulated depreciation and depletion		2,134,953			1,572,775			1,177,526
	Net capitalized costs		$	6,017,998		$	5,177,568		$	4,594,557
	Costs incurred for the years ended December 31:
	Property acquisition:
	Proved properties (b)		$	90,390		$	16,965		$	108,717
	Unproved properties		95,861			117,654			41,085
	Exploration (c)		4,285			4,827			2,344
	Development		1,230,301			850,854			928,294
	(a)                     Amounts exclude capital expenditures for facilities and information technology.
	(b)                     Amounts include $57.0 million for the purchase of Marcellus wells acquired in the Chesapeake acquisition in 2013 and $92.6 million of liabilities assumed in exchange for proved developed properties as part of the ANPI transaction in 2011.
	(c)                      Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.
	Results of Operations for Producing Activities
	The following table presents the results of operations related to natural gas, NGL and oil production.
			For the Years Ended December 31,
			2013			2012			2011
			(Thousands)
	Revenues:
	Affiliated		$	5,912		$	3,433		$	6,225
	Nonaffiliated		1,162,745			790,340			785,060
	Production costs		108,091			96,155			80,911
	Exploration costs		18,483			10,370			4,932
	Depreciation, depletion and accretion		578,641			409,628			257,144
	Income tax expense		183,060			109,660			174,835
	Results of operations from producing activities (excluding corporate overhead)		$	280,382		$	167,960		$	273,463
	Reserve Information
	The information presented below represents estimates of proved natural gas, NGL and oil reserves prepared by Company engineers.  The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree in Petroleum and Natural Gas Engineering from the Pennsylvania State University and has 25 years of experience in the oil and gas industry.  To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGL and oil reserves are audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management.  Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.
	Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment.  There were no differences between the internally prepared and externally audited estimates.  Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.  Ryder Scott reviewed 100% of the total net gas, NGL and oil proved reserves attributable to the Company’s interests as of December 31, 2013.  Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties.  This audit covered 80% of the Company’s proved reserves.  Ryder Scott’s audit of the remaining 20% of the Company’s properties consisted of an audit of aggregated groups not exceeding 200 wells per group.  The audit utilized the performance method and the analogy method.  Where historical reserve or production data was definitive, the performance method, which extrapolates historical data, was utilized.  In other cases the analogy method, which calculates reserves based on correlations to comparable surrounding wells, was utilized.  All of the Company’s proved reserves are located in the United States.
			Years Ended December 31,
			2013			2012			2011
			(Millions of Cubic Feet)
	Natural Gas
	Proved developed and undeveloped reserves:
	Beginning of year		5,985,758			5,347,386			5,205,692
	Revision of previous estimates		(375,887	)		(755,788	)		(393,129	)
	Purchase of natural gas in place		472,798			–			39,436
	Sale of natural gas in place		(455	)		(694	)		(1,223	)
	Extensions, discoveries and other additions		1,844,840			1,654,228			694,180
	Production		(365,493	)		(259,374	)		(197,570	)
	End of year		7,561,561			5,985,758			5,347,386
	Proved developed reserves:
	Beginning of year		2,779,187			2,948,546			2,520,569
	End of year		3,567,313			2,779,187			2,948,546
			Years Ended December 31,
			2013				2012				2011
			(Thousands of Bbls)
	Oil (a)
	Proved developed and undeveloped reserves:
	Beginning of year		3,199				2,931				2,307
	Revision of previous estimates		270				265				781
	Purchase of oil in place		–				–				51
	Sale of oil in place		–				–				–
	Extensions, discoveries and other additions		757				268				–
	Production		(270	)			(265	)			(208	)
	End of year		3,956				3,199				2,931
Proved developed reserves:
Beginning of year		3,199				2,931				2,307
End of year		3,892				3,199				2,931
(a)                      One thousand Bbl equals approximately 6 million cubic feet (MMcf).
		Year Ended
		December 31, 2013
NGLs (a)		(Thousands of Bbls)
Proved developed and undeveloped reserves:
Beginning of year		–
Revision of previous estimates		94,296
Purchase of NGLs in place		–
Sale of NGLs in place		–
Extensions, discoveries and other additions		32,866
Production		–
End of year		127,162
Proved developed reserves:
Beginning of year		–
End of year		65,837
(a)                     One thousand Bbl equals approximately 6 million cubic feet (MMcf).
As discussed in Note 8, the Company acquired the Class A interest in ANGT in May 2011. Prior to this acquisition, the Company held a 1% equity interest in ANGT which was accounted for under the equity method.  The Company’s share of these reserves and the impact on the standard measure of discounted future cash flow was not considered material and therefore was excluded from these measures prior to the acquisition.  This acquisition added 39.7 Bcfe of proved developed reserves.
During 2013, the Company recorded upward revisions of 191.5 Bcfe to the December 31, 2012 estimates of its reserves primarily due to the increase in the average NYMEX natural gas price for the year causing the properties to remain economic for a longer period. This increase was partially offset by negative revisions of 349 Bcfe, which was primarily due to the removal of 58 undeveloped locations and their associated reserves. The Company has included NGL reserves for the first time in 2013.  This caused a one-time decrease in gas reserves and an increase in equivalent reserves. Due to the continued growth in NGL reserves, the Company is separately calculating and presenting such reserves. The Company’s 2013 extensions, discoveries and other additions, resulting from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 2,046.6 Bcfe exceeded the 2013 production of 367.1 Bcfe. These reserve extensions and discoveries were mainly due to decreased lateral spacing in one of the Company’s locations in Greene County, Pennsylvania, and additional proved locations in the Company’s Pennsylvania and West Virginia Marcellus fields and the addition of Huron proved undeveloped reserves due to the re-establishment of the Huron development program.
During 2012, the Company recorded downward revisions of 754.2 Bcfe to the December 31, 2011 estimates of its reserves primarily due to the decrease in the average NYMEX natural gas price for the year causing the existing reserves to become uneconomic in accordance with SEC pricing requirements.  The Company’s 2012 extensions, discoveries and other additions, resulting from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 1,655.8 Bcfe exceeded the 2012 production of 261.0 Bcfe.  These reserve extensions and discoveries were mainly due to decreased lateral spacing in one of the Company’s Greene County, Pennsylvania locations and additional proved locations in the Company’s Wetzel and Doddridge County, West Virginia development areas.
During 2011, the Company recorded downward revisions of 388.4 Bcfe to the December 31, 2010 estimates of its reserves primarily due to removing proved undeveloped reserves in the Huron play in order to focus capital and resources in the Marcellus play over the five-year time horizon included in the proved undeveloped reserves development plan.  The Company’s 2011 extensions, discoveries and other additions, resulting from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery of 694.2 Bcfe exceeded the 2011 production of 198.8 Bcfe.
As of December 31, 2013, the Company did not have any reserves that have been classified as proved undeveloped reserves for more than five years.
Standard Measure of Discounted Future Cash Flow
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom.  The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.
Estimated future net cash flows from natural gas and oil reserves are as follows at December 31:
		2013				2012				2011
		(Thousands)
Future cash inflows (a)		$	25,912,542			$	15,250,019			$	22,145,953
Future production costs		(4,180,136		)		(3,070,957		)		(3,435,200		)
Future development costs		(4,199,722		)		(3,082,053		)		(2,600,982		)
Future income tax expenses		(6,533,817		)		(3,324,472		)		(6,075,539		)
Future net cash flow		10,998,867				5,772,537				10,034,232
10% annual discount for estimated timing of cash flows		(7,047,588		)		(3,617,378		)		(6,101,408		)
Standardized measure of discounted future net cash flows		$	3,951,279			$	2,155,159			$	3,932,824
(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2013, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013 of $89.22 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $3.653 per Dth for Columbia Gas Transmission Corp., $3.447 per Dth for Dominion Transmission, Inc., $3.693 per Dth for the East Tennessee Natural Gas Pipeline, $3.495 per Dth for Texas Eastern Transmission Corp., $2.842 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $3.521 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.
	For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012 of $82.90 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $2.793 per Dth for Columbia Gas Transmission Corp., $2.785 per Dth for Dominion Transmission, Inc., $2.769 per Dth for the East Tennessee Natural Gas Pipeline, $2.782 per Dth for Texas Eastern Transmission Corp., $2.403 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.878 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.  For 2012, the West Virginia Marcellus reserves from Doddridge and Ritchie Counties were computed using an additional $0.591 and reserves from Wetzel County were computed using an additional $0.398 for revenues earned on NGLs that are produced from those reserves.  Revenues earned on NGLs that are produced from certain Kentucky reserves were computed using an additional $0.764.
	For 2011, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011 of $92.84 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $4.198 per Dth for Columbia Gas Transmission Corp., $4.243 per Dth for Dominion Transmission, Inc., $4.159 per Dth for the East Tennessee Natural Gas Pipeline and $4.172 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.  The Company sold Langley on February 1, 2011.  As a result of that sale, management determined that the revenue received from the fractionation of NGLs which were extracted from the Company’s produced natural gas would be reported in EQT Production rather than EQT Midstream.  For 2011, the West Virginia Marcellus reserves and certain Kentucky reserves were computed using an additional $1.139 and $2.149, respectively, for revenues earned on NGLs that are produced from those reserves.
Holding production and development costs constant, a change in price of $1 per Dth for natural gas and $10 per barrel for oil would result in a change in the December 31, 2013 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $3.2 billion and $15.6 million, respectively.
Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:
		2013				2012				2011
		(Thousands)
Sales and transfers of natural gas and oil produced – net		$	(1,060,566	)		$	(697,618	)		$	(710,373	)
Net changes in prices, production and development costs		(292,533		)		(3,530,086		)		52,057
Extensions, discoveries and improved recovery, less related costs		1,509,002				917,986				806,597
Development costs incurred		1,319,135				548,852				498,175
Purchase of minerals in place – net		348,608				–				46,178
Sale of minerals in place – net		(252		)		(807		)		(1,124		)
Revisions of previous quantity estimates		106,170				(876,336		)		(356,830		)
Accretion of discount		343,502				622,072				478,165
Net change in income taxes		(1,031,105		)		1,127,272				(560,360		)
Timing and other		554,159				111,000				622,127
Net increase (decrease)		1,796,120				(1,777,665		)		874,612
Beginning of year		2,155,159				3,932,824				3,058,212
End of year		$	3,951,279			$	2,155,159			$	3,932,824

SCHEDULE_II_VALUATION_AND_QUAL

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2013
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	'
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	'
	SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
	FOR THE THREE YEARS ENDED DECEMBER 31, 2013
	Column A	Column B		Column C					Column D		Column E
	Description	Balance at		(Deductions)			Additions		Deductions		Balance at
		Beginning		Additions			Charged to		(a)		End of
		of Period		Charged to			Other				Period
				Costs and			Accounts
				Expenses
		(Thousands)
	Allowance for doubtful accounts:
	2013	$	5,883	$	(704	)	$	–	$	8	$	5,171
	2012	$	7,626	$	(1,637	)	$	–	$	106	$	5,883
	2011	$	7,324	$	327		$	–	$	25	$	7,626
	Note:
	(a)                      Amount represents customer accounts written off, less recoveries.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
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. EQT owns a 2.0% general partner interest, all incentive distribution rights and a 42.6% 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. The Company utilizes the equity method of accounting for companies where its ownership is less than or equal to 50% and significant influence exists.
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 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.
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.  During the years ended December 31, 2013, 2012 and 2011, the Company recorded losses for lower of cost or market adjustments of $0.4 million, $7.0 million and $7.2 million, respectively, which became 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,
		2013				2012
		(Thousands)
	Oil and gas producing properties, successful efforts method	$	8,152,951			$	6,750,343
	Accumulated depletion	(2,134,953		)		(1,572,775		)
	Net oil and gas producing properties	6,017,998				5,177,568
	Midstream plant	2,807,165				2,308,362
	Accumulated depreciation and amortization	(547,991		)		(483,358		)
	Net midstream plant	2,259,174				1,825,004
	Other properties, at cost less accumulated depreciation	56,590				56,840
	Net property, plant and equipment	$	8,333,762			$	7,059,412
	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 $93.5 million, $72.1 million and $69.3 million in 2013, 2012 and 2011, respectively.  The Company capitalized $22.9 million, $15.6 million and $13.3 million of interest relative to Marcellus well development in 2013, 2012 and 2011, 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 oil and gas producing properties consist of gas producing properties which were depleted at an overall average rate of $1.50 per Mcfe, $1.52 per Mcfe and $1.25 per Mcfe produced for the years ended December 31, 2013, 2012 and 2011, 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 risk-adjusted proved and, in some cases, 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.  For the years ended December 31, 2013, 2012 and 2011, the Company did not recognize impairment charges on developed oil and gas properties.
	Capitalized costs of unproved 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.  Undeveloped properties had a net book value of $450.2 million and $385.6 million at December 31, 2013 and 2012, respectively. Undeveloped property impairments primarily as a result of lease expirations prior to drilling of $14.2 million, $5.5 million and $2.6 million are included in exploration expense for the years ended December 31, 2013, 2012 and 2011, respectively.
	At December 31, 2013 and 2012, the Company had no capitalized exploratory well costs.
	Midstream property, plant and equipment is carried at cost.  Depreciation is calculated using the straight-line method based on estimated service lives.  Midstream property consists largely of gathering and transmission systems (25-60 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).
	Major maintenance projects that do not increase the overall life of the related assets are expensed.  When major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.
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,
		2013			2012			2011
		(Thousands)
	Midstream revenues	$	184,767		$	131,184		$	113,774
	Midstream operating expenses	$	71,517		$	66,202		$	76,247
	The following table presents the regulated net property, plant and equipment included in EQT Midstream:
		As of December 31,
		2013				2012
		(Thousands)
	Property, plant & equipment	$	1,015,118			$	797,405
	Accumulated depreciation and amortization	(158,533		)		(143,714		)
	Net property, plant & equipment	$	856,585			$	653,691
	The regulatory assets associated with deferred taxes of $13.3 million and $18.3 million as of December 31, 2013 and 2012, 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.
Derivative Instruments:	'
	Derivative Instruments:  Derivatives are held as part of a formally documented risk management program.  The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC).  The CRC reports to the Audit Committee of the Board of Directors and is composed of the president and chief executive officer, the chief financial officer and other officers and employees.
	The Company’s risk management program includes the consideration and, when appropriate, the use of (i) exchange-traded natural gas futures contracts and options and over the counter (OTC) natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and (ii) 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 earnings 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.
	For a derivative instrument that has been designated and qualifies as a fair value hedge, the change in the fair value for the instrument is 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) is 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.  Effective October 1, 2013, the Company de-designated all derivative commodity instruments that were previously designated and qualified as fair value hedges.
	Any changes in fair value of derivative instruments that have not been designated as hedges are recognized in the Statements of Consolidated Income each period.
	If a cash flow hedge is terminated or de-designated as a hedge before the settlement date of the hedged item, the amount of accumulated OCI recorded up to that date remains accrued, provided that the forecasted transaction remains 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 which are currently designated as cash flow hedges.
	The Company reports all gains and losses on its energy trading contracts 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 $4.3 million, $3.9 million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, 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 $1.2 million, $6.8 million and $3.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Impairment of Long-Lived Assets:	'
	Impairment of Long-Lived Assets:  When events or changes in circumstances indicate that the carrying amount of long-lived assets 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.
Other Current Liabilities:	'
	Other Current Liabilities:  Other current liabilities as of December 31, 2013 and 2012 are detailed below.
		December 31,
		2013				2012
		(Thousands)
	Incentive compensation	$	65,053			$	52,291
	Taxes other than income	39,073				37,048
	Accrued interest payable	29,379				29,878
	All other accrued liabilities	18,763				27,388
	Total other current liabilities	$	152,268			$	146,605
Revenue Recognition:	'
	Revenue Recognition:  Revenue is recognized for production and gathering activities when deliveries of natural gas, NGLs and crude oil are made. 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.  Revenues associated with energy trading contracts that do not result in physical delivery of an energy commodity are classified as derivative instruments. 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 42.6% 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. 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) 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.  The Company recognizes a loss in the value of an equity method investment that is other than a temporary decline.  The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable.
Purchased Gas Costs:	'
	Purchased Gas Costs:  Purchased gas costs in the Statements of Consolidated Income include natural gas wellhead purchases, natural gas field line purchases, natural gas transmission line purchases, purchased gas cost adjustments, natural gas withdrawn from storage, gas used for product extraction and other gas supply expenses, including pipeline demand charges and transportation costs.
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 on 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,
		2013			2012
		(Thousands)
	Asset retirement obligation as of beginning of period	$	109,034		$	102,439
	Accretion expense	8,342			7,716
	Liabilities incurred	2,510			1,141
	Liabilities settled	(3,353		)	-2,408
	Revisions in estimated cash flows	(488		)	146
	Asset retirement obligation as of end of period	$	116,045		$	109,034
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.
Accumulated other comprehensive income:	'
	Accumulated other comprehensive income: The components of accumulated OCI, net of tax, are as follows:
		As of December 31,
		2013			2012
		(Thousands)
	Net unrealized gain from natural gas hedging transactions	$	61,699		$	138,188
	Net unrealized loss from interest rate swaps	-1,132			-1,276
	Pension and other post-retirement benefits liability adjustment	-15,864			-37,365
	Accumulated OCI	$	44,703		$	99,547
Noncontrolling interest:	'
	Noncontrolling interest: 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.
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, 2013
Summary of Significant Accounting Policies	'
Schedule of Property, Plant and Equipment	'
		As of December 31,
		2013				2012
		(Thousands)
	Oil and gas producing properties, successful efforts method	$	8,152,951			$	6,750,343
	Accumulated depletion	(2,134,953		)		(1,572,775		)
	Net oil and gas producing properties	6,017,998				5,177,568
	Midstream plant	2,807,165				2,308,362
	Accumulated depreciation and amortization	(547,991		)		(483,358		)
	Net midstream plant	2,259,174				1,825,004
	Other properties, at cost less accumulated depreciation	56,590				56,840
	Net property, plant and equipment	$	8,333,762			$	7,059,412
Schedule of regulated net revenues and operating expenses	'
		Years Ended December 31,
		2013			2012			2011
		(Thousands)
	Midstream revenues	$	184,767		$	131,184		$	113,774
	Midstream operating expenses	$	71,517		$	66,202		$	76,247
Regulated net property, plant and equipment	'
		As of December 31,
		2013				2012
		(Thousands)
	Property, plant & equipment	$	1,015,118			$	797,405
	Accumulated depreciation and amortization	(158,533		)		(143,714		)
	Net property, plant & equipment	$	856,585			$	653,691
Schedule of other current liabilities	'
		December 31,
		2013				2012
		(Thousands)
	Incentive compensation	$	65,053			$	52,291
	Taxes other than income	39,073				37,048
	Accrued interest payable	29,379				29,878
	All other accrued liabilities	18,763				27,388
	Total other current liabilities	$	152,268			$	146,605
Reconciliation of the beginning and ending carrying amounts of asset retirement obligations	'
		Years Ended December 31,
		2013			2012
		(Thousands)
	Asset retirement obligation as of beginning of period	$	109,034		$	102,439
	Accretion expense	8,342			7,716
	Liabilities incurred	2,510			1,141
	Liabilities settled	(3,353		)	-2,408
	Revisions in estimated cash flows	(488		)	146
	Asset retirement obligation as of end of period	$	116,045		$	109,034
Schedule of components of accumulated OCI, net of tax	'
		As of December 31,
		2013			2012
		(Thousands)
	Net unrealized gain from natural gas hedging transactions	$	61,699		$	138,188
	Net unrealized loss from interest rate swaps	-1,132			-1,276
	Pension and other post-retirement benefits liability adjustment	-15,864			-37,365
	Accumulated OCI	$	44,703		$	99,547

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2013
Discontinued Operations	'
Summary of the components of discontinued operations activity	'
		Years Ended December 31,
		2013		2012		2011
		(Thousands)
	Operating revenues	$	332,947	$	314,821	$	420,563
	Income from discontinued operations before income taxes	251,378		81,328		101,010
	Income taxes	159,535		33,835		40,823
	Income from discontinued operations, net of tax	$	91,843	$	47,493	$	60,187
Schedule of assets and liabilities of discontinued operations included in the Consolidated Balance Sheet	'
		As of
		December 31, 2012
		(Thousands)
	Assets
	Accounts receivable and unbilled receivables	$	42,919
	Inventory	31,622
	Other current assets	18,137
	Total current assets	92,678
	Property, plant and equipment, net	655,886
	Regulatory assets	93,599
	Other assets	571
	Total noncurrent assets	750,056
	Assets of discontinued operations	$	842,734
	Liabilities
	Accounts payable	$	12,230
	Accrued customer credits	32,376
	Other current liabilities	3,685
	Total current liabilities	48,291
	Deferred income taxes	223,959
	Pension and other post-retirement benefits	27,985
	Other liabilities	5,671
	Total noncurrent liabilities	257,615
	Liabilities of discontinued operations	$	305,906

Financial_Information_by_Busin1

Financial Information by Business Segment (Tables)	12 Months Ended
	Dec. 31, 2013
Financial Information by Business Segment	'
Schedule of revenue from external customers and operating income	'
		Years Ended December 31,
		2013		2012		2011
				(Thousands)
	Revenues from external customers:
	EQT Production	$	1,168,657	$	793,773	$	791,285
	EQT Midstream	614,042		505,498		525,345
	Third-party transportation costs (a)	142,281		126,783		87,034
	Less intersegment revenues, net (b)	-62,969		-48,832		-79,835
	Total	$	1,862,011	$	1,377,222	$	1,323,829
	Operating income:
	EQT Production	$	371,245	$	187,913	$	387,098
	EQT Midstream (c)	328,782		237,324		416,611
	Unallocated expenses (d)	-45,423		-35,608		-42,538
	Total operating income	$	654,604	$	389,629	$	761,171
	(a)         This amount reflects the reclassification of third-party transportation costs from operating revenues to purchased gas 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, $36.8 million and $37.9 million for the years ended December 31, 2013, 2012 and 2011, 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, $11.7 million and $64.5 million for the years ended December 31, 2013, 2012 and 2011, 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)   Gains on dispositions of $19.6 million and $202.9 million are included in EQT Midstream operating income for 2013 and 2011, respectively.  See Note 7.
	(d)  Unallocated expenses consist primarily of incentive compensation, administrative costs and corporate overhead charges previously allocated to the Distribution segment that were reclassified to Headquarters as part of the recast of this Annual Report on Form 10-K to reflect the discontinued operations presentation requirements.
Reconciliation of operating income to income from continuing operations	'
		Years Ended December 31,
		2013		2012		2011
				(Thousands)
	Reconciliation of operating income to income from continuing operations:
	Other income	$	9,242	$	15,536	$	33,276
	Interest expense	142,688		184,786		136,328
	Income taxes	175,186		71,461		238,537
	Income from continuing operations	$	345,972	$	148,918	$	419,582
Schedule of segment assets	'
		As of December 31,
		2013		2012
		(Thousands)
	Segment assets:
	EQT Production	$	6,359,065	$	5,675,534
	EQT Midstream	2,514,429		2,046,558
	Total operating segments	8,873,494		7,722,092
	Headquarters assets, including cash and short-term investments	918,559		1,127,770
	Total assets	$	9,792,053	$	8,849,862
Schedule of depreciation, depletion and amortization and expenditures for segment assets	'
		Years Ended December 31,
		2013		2012		2011
				(Thousands)
	Depreciation, depletion and amortization:
	EQT Production	$	578,641	$	409,628	$	257,144
	EQT Midstream	75,032		64,782		57,135
	Other	-541		207		-411
	Total	$	653,132	$	474,617	$	313,868
	Expenditures for segment assets:
	EQT Production (e)	$	1,423,185	$	991,775	$	1,087,840
	EQT Midstream	369,399		375,731		242,886
	Other	4,292		3,134		4,855
	Total	$	1,796,876	$	1,370,640	$	1,335,581
	(e)          Expenditures for segment assets in the EQT Production segment include $186.2 million, $134.6 million and $57.2 million for property acquisitions in 2013, 2012 and 2011, respectively.  Expenditures for segment assets in the EQT Production segment also include $92.6 million of liabilities assumed in exchange for producing properties as part of the ANPI transaction, as described in Note 8, in 2011.

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments	'
Derivatives designated and not designated as hedging instruments	'
		Years Ended December 31,
		2013		2012		2011
				(Thousands)
	Commodity derivatives designated as cash flow hedges
	Amount of gain recognized in OCI (effective portion), net of tax	$	10,669	$	86,259	$	239,019
	Amount of gain reclassified from accumulated OCI, net of tax into operating revenues (effective portion)	87,158		180,137		72,179
	Amount of (loss) recognized in operating revenues (ineffective portion) (a)	-21,335		-75		-181
	Interest rate derivatives designated as cash flow hedges
	Amount of (loss) recognized in OCI (effective portion), net of tax	$	–	$	-7,138	$	-7,573
	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)	-144		-241		-140
	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	$	12,263
	Fair value gain (loss) recognized in operating revenues for inventory designated as hedged item	386		3,292		-6,059
	Derivatives not designated as hedging instruments
	Amount of gain recognized in operating revenues	$	2,834	$	2,176	$	4,209
	(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. For the year ended December 31, 2011, 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 $1.4 million loss due to changes in basis.
Asset and liability derivatives	'
		As of December 31,
		2013		2012
		(Thousands)
	Asset derivatives
	Commodity derivatives designated as hedging instruments	$	104,430	$	259,459
	Commodity derivatives not designated as hedging instruments	3,217		44,778
	Total asset derivatives	$	107,647	$	304,237
	Liability derivatives
	Commodity derivatives designated as hedging instruments	$	27,618	$	27,946
	Commodity derivatives not designated as hedging instruments	2,033		47,616
	Total liability derivatives	$	29,651	$	75,562
Schedule of impact of netting agreements and margin deposits on gross derivative assets and liabilities	'
	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
	As of December 31, 2012	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	$	304,237	$	-73,753	$	–	$	230,484
	Liability derivatives:
	Derivative instruments, at fair value	$	75,562	$	-73,753	$	-736	$	1,073

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements	'
Derivative instrument assets and liabilities measured at fair value on a recurring basis	'
				Fair value measurements at reporting date using
	Description	December 31,		Quoted		Significant		Significant
		2013		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 at reporting date using
	Description	December 31,		Quoted		Significant		Significant
		2012		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	$	304,237	$	1,228	$	204,592	$	98,417
	Liabilities
	Derivative instruments, at fair value	$	75,562	$	1,609	$	66,250	$	7,703
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,
		2013		2012
		(Thousands)
	Balance at January 1	$	90,714	$	143,260
	Total gains or losses:
	Included in earnings	640		-615
	Included in OCI	-2,554		23,386
	Purchases	–		-933
	Settlements	-34,381		-74,384
	Transfers in and/or out of Level 3	-54,419		–
	Balance at December 31	$	–	$	90,714

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
Schedule of income tax expense (benefit) from continuing operations	'
		Years Ended December 31,
		2013		2012		2011
		(Thousands)
	Current:
	Federal	$	100,796	$	3,771	$	30,837
	State	46,758		229		1,434
	Subtotal	147,554		4,000		32,271
	Deferred:
	Federal	51,767		56,551		177,474
	State	-23,940		11,014		29,003
	Subtotal	27,827		67,565		206,477
	Amortization of deferred investment tax credit	-195		-104		-211
	Total income taxes	$	175,186	$	71,461	$	238,537
Reconciliation of income tax expense to amount computed at the federal statutory rate	'
		Years Ended December 31,
		2013		2012		2011
		(Thousands)
	Tax at statutory rate	$	182,406	$	77,133	$	230,342
	State income taxes	16,180		2,869		18,150
	Federal tax credits and incentives	-750		-439		-660
	Permanent basis differences	-407		-2,789		-2,020
	Noncontrolling partners’ share of Partnership earnings	-16,535		-4,571		–
	Other	-5,708		-742		-7,275
	Income tax expense	$	175,186	$	71,461	$	238,537
	Effective tax rate	33.60%		32.40%		36.20%
Reconciliation of the beginning and ending amount of reserve for uncertain tax positions(excluding interest and penalties)	'
		2013		2012		2011
		(Thousands)
	Balance at January 1	$	17,858	$	30,730	$	37,943
	Additions based on tax positions related to current year	49,289		2,165		1,245
	Additions for tax positions of prior years	–		2,320		184
	Settlements	–		–		–
	Reductions for tax positions of prior years	-790		-12,235		-7,886
	Lapse of statute of limitations	-9,270		-5,122		-756
	Balance at December 31	$	57,087	$	17,858	$	30,730
Summary of net deferred income tax liabilities (assets)	'
		As of December 31,
		2013		2012
		(Thousands)
	Deferred income taxes:
	Total deferred income tax assets .	$	-670,368	$	-696,252
	Total deferred income tax liabilities	2,295,128		2,122,377
	Total net deferred income tax liabilities	1,624,760		1,426,125
	Total deferred income tax liabilities (assets)
	Drilling and development costs expensed for income tax reporting	1,181,375		933,800
	Tax depreciation in excess of book depreciation	923,443		924,229
	Investment in Partnership	101,569		108,764
	Accumulated OCI	28,597		81,087
	Post-retirement benefits	-3,946		-3,784
	Incentive compensation	-60,982		-28,811
	Alternative minimum tax credit carryforward	-246,157		-69,901
	Net operating loss carryforwards	-359,283		-593,756
	Other	3,740		8,261
	Total excluding valuation allowances	1,568,356		1,359,889
	Valuation allowance	56,404		66,236
	Total (including amounts classified as current assets of $31,005 and $15,946, respectively)	$	1,624,760	$	1,426,125

Equity_in_Nonconsolidated_Inve1

Equity in Nonconsolidated Investments (Tables)	12 Months Ended
	Dec. 31, 2013
Equity in Nonconsolidated Investments	'
Equity in the nonconsolidated investments	'
				Interest		Ownership	As of December 31,
						as of
						December
	Investees	Location		Type		31, 2013	2013		2012
							(Thousands)
	Nora Gathering, LLC (Nora LLC)	USA		Joint		50%	$	128,983	$	130,368
Schedule of summarized balance sheet for nonconsolidated investments accounted for under the equity method of accounting	'
	Summarized Balance Sheets
		As of December 31,
		2013			2012
		(Thousands)
	Current assets	$	27,014		$	15,966
	Noncurrent assets	239,583			249,347
	Total assets	$	266,597		$	265,313
	Current liabilities	$	8,529		$	4,476
	Stockholders’ equity	258,068			260,837
	Total liabilities and stockholders’ equity	$	266,597		$	265,313
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,
		2013			2012		2011
		(Thousands)
	Revenues	$	45,040		$	47,888	$	49,772
	Operating expenses	29,810			35,596		35,520
	Net income	$	15,230		$	12,292	$	14,252

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-Term Debt	'
Long-Term Debt	'
		As of December 31,
		2013		2012
		(Thousands)
	7.76% notes, due 2014 thru 2016	$	18,316	$	32,973
	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
	7.75% debentures, due July 15, 2026	115,000		115,000
	Medium-term notes:
	8.7% to 9.0% Series A, due 2014 thru 2021	40,200		40,200
	7.3% to 7.6% Series B, due 2015 thru 2023	20,000		30,000
	7.6% Series C, due 2018	8,000		8,000
		2,501,516		2,526,173
	Less debt payable within one year	11,162		23,204
	Total long-term debt	$	2,490,354	$	2,502,969

Pension_and_Other_PostRetireme1

Pension and Other Post-Retirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Pension and Other Post-Retirement Benefit Plans	'
Schedule of funded status and amounts recognized for defined benefit pension and other post-retirement benefit plans	'
		For the Years Ended December 31,
		2013				2012				2013			2012
		Pension Benefits								Other Benefits
		(Thousands)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	63,270			$	61,885			$	36,255		$	35,293
	Service cost	500				500				905			737
	Interest cost	1,935				2,448				1,110			1,427
	Amendments	–				(126		)		–			–
	Actuarial loss	(3,038		)		5,733				(2,355		)	2,656
	Benefits paid	(5,269		)		(5,571		)		(3,961		)	(3,858		)
	Expenses paid	(493		)		(511		)		–			–
	Divestitures	(34,410		)		–				(13,701		)	–
	Settlements	(667		)		(1,088		)		–			–
	Subtotal	21,828				63,270				18,253			36,255
	Benefit obligation included in discontinued operations	–				42,835				–			15,577
	Benefit obligation at end of year	$	21,828			$	20,435			$	18,253		$	20,678
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	46,984			$	45,951			$	165		$	19
	Actual gain on plan assets	7,304				5,346				–			–
	Contributions	2,639				2,857				328			146
	Benefits paid	(5,269		)		(5,571		)		–			–
	Expenses paid	(493		)		(511		)		–			–
	Divestitures	(30,409		)		–				–			–
	Settlements	(667		)		(1,088		)		–			–
	Subtotal	20,089				46,984				493			165
	Fair value of plan assets included in discontinued operations	–				30,428				–			–
	Fair value of plan assets at end of year	20,089				16,556				493			165
	Funded status at end of year	$	(1,739	)		$	(3,879	)		$	(17,760	)	$	(20,513	)
Schedule of amounts recognized in statement of financial position	'
	Amounts recognized in the statement of financial position consist of:
	Current liabilities	$	–			$	–			$	(1,341	)	$	(3,353	)
	Noncurrent liabilities	(1,739		)		(3,879		)		(16,419		)	(17,160		)
	Net amounts recognized	$	(1,739	)		$	(3,879	)		$	(17,760	)	$	(20,513	)
	Amounts recognized in accumulated OCI, net of tax, consist of:
	Net loss	$	7,524			$	24,634			$	8,234		$	14,291
	Net prior service (credit)	–				–				106			(1,560		)
	Net amount recognized	$	7,524			$	24,634			$	8,340		$	12,731
Schedule of components of net periodic benefit cost	'
		For the Years Ended December 31,
		2013				2012				2011			2013				2012			2011
		Pension Benefits											Other Benefits
		(Thousands)
	Components of net periodic benefit cost:
	Service cost	$	500			$	500			$	500		$	905			$	737		$	620
	Interest cost	1,935				2,448				3,115			1,110				1,427			1,771
	Expected return on plan assets	(3,323		)		(3,712		)		(4,070		)	–				–			–
	Amortization of prior service cost	–				–				–			(845		)		(845		)	(902		)
	Recognized net actuarial loss	2,306				1,880				1,471			1,760				1,671			1,605
	Settlement loss and special termination benefits	381				725				530			–				–			–
	Subtotal	1,799				1,841				1,546			2,930				2,990			3,094
	Net periodic benefit cost of discontinued operations	1,552				1,586				1,387			1,356				1,288			1,427
	Net periodic benefit cost	$	247			$	255			$	159		$	1,574			$	1,702		$	1,667
Schedule of amount recognized in other comprehensive income	'
		For the Years Ended December 31,
		2013				2012				2011			2013				2012			2011
		Pension Benefits											Other Benefits
		(Thousands)
	Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
	Net (gain) loss	$	712			$	261			$	3,378		$	2,147			$	494		$	181
	Net prior service cost	–				–				–			416				330			915
	Total recognized in OCI, net of tax	$	712			$	261			$	3,378		$	2,563			$	824		$	1,096
	Total recognized in net periodic benefit cost and OCI, net of tax	$	959			$	2,102			$	4,924		$	4,137			$	3,814		$	4,190
Schedule of assumption used to determine the benefit obligations	'
		December 31,
		2013		2012		2013		2012
		Pension Benefits				Other Benefits
	Discount rate	4.00%		3.25%		4.00%		3.25%
	Rate of compensation increase	N/A		N/A		N/A		N/A
Schedule of assumption used to determine the net periodic benefit cost	'
		For the Years Ended December 31,
		2013			2012			2013			2012
		Pension Benefits						Other Benefits
	Discount rate	3.25%			4.25%			3.25%			4.25%
	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	'
		One-Percentage-Point									One-Percentage-Point
		Increase									Decrease
		2013			2012			2011			2013		2012			2011
		(Thousands)
	Increase (decrease) to total of service and interest cost components	$	25		$	32		$	40		$	-26	$	-32		$	-39
	Increase (decrease) to post-retirement benefit obligation	$	220		$	711		$	730		$	-223	$	-688		$	-702
Schedule of the entity's asset allocation	'
				Percentage of Plan Assets
		Target		at December 31,
	Asset Category	Allocation 2014		2013			2012
	Domestic broadly diversified equity securities	40% - 60%		42	%		53	%
	Fixed income securities	20% - 50%		29	%		32	%
	International broadly diversified equity securities	5% - 15%		7	%		10	%
	Alternative fixed income securities	0% - 10%		4	%		4	%
	Cash and equivalent investments	0% - 15%		18	%		1	%
				100	%		100	%

Changes_in_Accumulated_Other_C1

Changes in Accumulated Other Comprehensive Income by Component (Tables)	12 Months Ended
	Dec. 31, 2013
Changes in Accumulated Other Comprehensive Income by Component	'
Schedule of the changes in accumulated OCI by component	'
		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
	Amounts reclassified from accumulated OCI into realized (income) expense, 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, 2013
Common Stock and Earnings Per Share	'
Reserved, authorized and unissued common stock	'
	At December 31, 2013, shares of EQT’s authorized and unissued common stock were reserved as follows:
		(Thousands)
	Possible future acquisitions	20,457
	Stock compensation plans	8,911
	Total	29,368
Computation of basic and diluted earnings per share of common stock	'
		Years Ended December 31,
		2013		2012		2011
		(Thousands except per share amounts)
	Basic earnings per common share:
	Net income attributable to EQT Corporation	$	390,572	$	183,395	$	479,769
	Average common shares outstanding	150,574		149,619		149,392
	Basic earnings per common share	$	2.59	$	1.23	$	3.21
	Diluted earnings per common share:
	Net income attributable to EQT Corporation	$	390,572	$	183,395	$	479,769
	Average common shares outstanding	150,574		149,619		149,392
	Potentially dilutive securities:
	Stock options and awards (a)	1,213		887		817
	Total	151,787		150,506		150,209
	Diluted earnings per common share	$	2.57	$	1.22	$	3.19
	(a)         There were no options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive for the year ended December 31, 2013. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 281,528 and 6,480 shares for the year ended December 31, 2012 and 2011, respectively.

ShareBased_Compensation_Plans_

Share-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Share-Based Compensation Plans	'
Share-based compensation expense	'
		Years Ended December 31,
		2013				2012				2011
		(Thousands)
	2008 Executive Performance Incentive Program	$	–			$	–			$	923
	2010 Executive Performance Incentive Programs	–				1,940				2,118
	2012 Executive Performance Incentive Program	6,739				10,633				–
	2013 Executive Performance Incentive Program	6,602				–				–
	2007 Supply Long-Term Incentive Program	–				–				198
	2010 Stock Incentive Award Program	–				4,022				4,241
	2011 EQT Value Driver Award Program	–				3,033				15,807
	2012 EQT Value Driver Award Program	2,327				11,557				–
	2013 EQT Value Driver Award Program	13,050				–				–
	2011 Volume and Efficiency Program	13,834				5,286				5,384
	Restricted stock awards	3,033				2,007				1,929
	Non-qualified stock options	3,805				3,580				6,057
	Non-employee directors’ share-based awards	7,432				2,558				3,320
	EQM Total Return Program	837				419				–
	EQM non-employee directors’ share-based awards	144				116				–
	Expense attributable to discontinued operations	741				670				352
	Total share-based compensation expense	$	58,544			$	45,821			$	40,329
Summary of restricted stock awards activity during the period	'
	Restricted Stock	Non-			Weighted		Aggregate
		Vested			Average		Fair Value
		Shares			Fair Value
	Outstanding at January 1, 2013	204,118			$	49.86	$	10,176,930
	Granted	101,510			$	70.59	7,166,006
	Vested	(91,478	)		$	46.87	(4,287,701		)
	Forfeited	(31,772	)		$	55.15	(1,752,243		)
	Outstanding at December 31, 2013	182,378			$	61.98	$	11,302,992
Non-Qualified Stock Options, assumptions used to value share-based compensation	'
		Years Ended December 31,
		2013		2012		2011
	Risk-free interest rate	0.76%		0.89%		2.02%
	Dividend yield	0.22%		1.64%		2.19%
	Volatility factor	31.69%		31.44%		28.92%
	Expected term	5 years		5 years		5 years
Summary of option activity	'
	Non-qualified Stock Options	Shares		Weighted		Weighted		Aggregate
				Average		Average		Intrinsic
				Exercise		Remaining		Value
				Price		Contractual
						Term
	Outstanding at January 1, 2013	1,864,375		$   46.01
	Granted	259,600		$   58.98
	Exercised	-637,174		$   42.44
	Forfeited	-4,800		$   58.98
	Outstanding at December 31, 2013	1,482,001		$   49.77		4.7 years		$ 59,287,589
	Exercisable at December 31, 2013	1,088,051		$   46.98		3.3 years		$ 46,570,891

Interim_Financial_Information_1

Interim Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Interim Financial Information (Unaudited)	'
Interim Financial Information (Unaudited)	'
		Three Months Ended
		March 31		June 30		September 30		December 31
		(Thousands, except per share amounts)
	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
	2012 (a)
	Operating revenues	$	334,291	$	298,742	$	337,916	$	406,273
	Operating income	111,054		70,817		81,253		126,505
	Amounts attributable to EQT Corporation:
	Income from continuing operations	48,467		25,302		29,010		33,123
	Income from discontinued operations	23,568		6,144		2,863		14,918
	Net income attributable to EQT Corporation	$	72,035	$	31,446	$	31,873	$	48,041
	Earnings per share of common stock attributable to EQT Corporation:
	Basic:
	Income from continuing operations	$	0.32	$	0.17	$	0.19	$	0.22
	Income from discontinued operations	0.16		0.04		0.02		0.1
	Net income	$	0.48	$	0.21	$	0.21	$	0.32
	Diluted:
	Income from continuing operations	$	0.32	$	0.17	$	0.19	$	0.22
	Income from discontinued operations	0.16		0.04		0.02		0.1
	Net income	$	0.48	$	0.21	$	0.21	$	0.32
	(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, 2013
Natural Gas Producing Activities (Unaudited)	'
Schedule of capitalized cost incurred relating to natural gas, NGL and oil production activities	'
	The following table presents the costs incurred relating to natural gas, NGL and oil production activities (a):
			For the Years Ended December 31,
			2013			2012			2011
			(Thousands)
	At December 31:
	Capitalized costs		$	8,152,951		$	6,750,343		$	5,772,083
	Accumulated depreciation and depletion		2,134,953			1,572,775			1,177,526
	Net capitalized costs		$	6,017,998		$	5,177,568		$	4,594,557
	(a)                     Amounts exclude capital expenditures for facilities and information technology.
Schedule of cost incurred relating to property acquisition, exploration and development	'
	Costs incurred for the years ended December 31:
	Property acquisition:
	Proved properties (b)		$	90,390		$	16,965		$	108,717
	Unproved properties		95,861			117,654			41,085
	Exploration (c)		4,285			4,827			2,344
	Development		1,230,301			850,854			928,294
	(b)                     Amounts include $57.0 million for the purchase of Marcellus wells acquired in the Chesapeake acquisition in 2013 and $92.6 million of liabilities assumed in exchange for proved developed properties as part of the ANPI transaction in 2011.
	(c)                      Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.
Results of Operations for Producing Activities	'
			For the Years Ended December 31,
			2013			2012			2011
			(Thousands)
	Revenues:
	Affiliated		$	5,912		$	3,433		$	6,225
	Nonaffiliated		1,162,745			790,340			785,060
	Production costs		108,091			96,155			80,911
	Exploration costs		18,483			10,370			4,932
	Depreciation, depletion and accretion		578,641			409,628			257,144
	Income tax expense		183,060			109,660			174,835
	Results of operations from producing activities (excluding corporate overhead)		$	280,382		$	167,960		$	273,463
Schedule of the entity's proved reserves	'
			Years Ended December 31,
			2013			2012			2011
			(Millions of Cubic Feet)
	Natural Gas
	Proved developed and undeveloped reserves:
	Beginning of year		5,985,758			5,347,386			5,205,692
	Revision of previous estimates		(375,887	)		(755,788	)		(393,129	)
	Purchase of natural gas in place		472,798			–			39,436
	Sale of natural gas in place		(455	)		(694	)		(1,223	)
	Extensions, discoveries and other additions		1,844,840			1,654,228			694,180
	Production		(365,493	)		(259,374	)		(197,570	)
	End of year		7,561,561			5,985,758			5,347,386
	Proved developed reserves:
	Beginning of year		2,779,187			2,948,546			2,520,569
	End of year		3,567,313			2,779,187			2,948,546
			Years Ended December 31,
			2013				2012				2011
			(Thousands of Bbls)
	Oil (a)
	Proved developed and undeveloped reserves:
	Beginning of year		3,199				2,931				2,307
	Revision of previous estimates		270				265				781
	Purchase of oil in place		–				–				51
	Sale of oil in place		–				–				–
	Extensions, discoveries and other additions		757				268				–
	Production		(270	)			(265	)			(208	)
	End of year		3,956				3,199				2,931
	Proved developed reserves:
	Beginning of year		3,199				2,931				2,307
	End of year		3,892				3,199				2,931
	(a)                      One thousand Bbl equals approximately 6 million cubic feet (MMcf).
			Year Ended
			December 31, 2013
	NGLs (a)		(Thousands of Bbls)
	Proved developed and undeveloped reserves:
	Beginning of year		–
	Revision of previous estimates		94,296
	Purchase of NGLs in place		–
	Sale of NGLs in place		–
	Extensions, discoveries and other additions		32,866
	Production		–
	End of year		127,162
	Proved developed reserves:
	Beginning of year		–
	End of year		65,837
	(a)                     One thousand Bbl equals approximately 6 million cubic feet (MMcf).
Schedule of estimated future net cash flows from natural gas and oil reserves	'
			2013				2012				2011
			(Thousands)
	Future cash inflows (a)		$	25,912,542			$	15,250,019			$	22,145,953
	Future production costs		(4,180,136		)		(3,070,957		)		(3,435,200		)
	Future development costs		(4,199,722		)		(3,082,053		)		(2,600,982		)
	Future income tax expenses		(6,533,817		)		(3,324,472		)		(6,075,539		)
	Future net cash flow		10,998,867				5,772,537				10,034,232
	10% annual discount for estimated timing of cash flows		(7,047,588		)		(3,617,378		)		(6,101,408		)
	Standardized measure of discounted future net cash flows		$	3,951,279			$	2,155,159			$	3,932,824
	(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2013, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013 of $89.22 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $3.653 per Dth for Columbia Gas Transmission Corp., $3.447 per Dth for Dominion Transmission, Inc., $3.693 per Dth for the East Tennessee Natural Gas Pipeline, $3.495 per Dth for Texas Eastern Transmission Corp., $2.842 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $3.521 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.
		For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012 of $82.90 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $2.793 per Dth for Columbia Gas Transmission Corp., $2.785 per Dth for Dominion Transmission, Inc., $2.769 per Dth for the East Tennessee Natural Gas Pipeline, $2.782 per Dth for Texas Eastern Transmission Corp., $2.403 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.878 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.  For 2012, the West Virginia Marcellus reserves from Doddridge and Ritchie Counties were computed using an additional $0.591 and reserves from Wetzel County were computed using an additional $0.398 for revenues earned on NGLs that are produced from those reserves.  Revenues earned on NGLs that are produced from certain Kentucky reserves were computed using an additional $0.764.
		For 2011, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011 of $92.84 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $4.198 per Dth for Columbia Gas Transmission Corp., $4.243 per Dth for Dominion Transmission, Inc., $4.159 per Dth for the East Tennessee Natural Gas Pipeline and $4.172 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.  The Company sold Langley on February 1, 2011.  As a result of that sale, management determined that the revenue received from the fractionation of NGLs which were extracted from the Company’s produced natural gas would be reported in EQT Production rather than EQT Midstream.  For 2011, the West Virginia Marcellus reserves and certain Kentucky reserves were computed using an additional $1.139 and $2.149, respectively, for revenues earned on NGLs that are produced from those reserves.
Schedule of changes in the standardized measure of discounted net cash flows from natural gas and oil reserves	'
			2013				2012				2011
			(Thousands)
	Sales and transfers of natural gas and oil produced – net		$	(1,060,566	)		$	(697,618	)		$	(710,373	)
	Net changes in prices, production and development costs		(292,533		)		(3,530,086		)		52,057
	Extensions, discoveries and improved recovery, less related costs		1,509,002				917,986				806,597
	Development costs incurred		1,319,135				548,852				498,175
	Purchase of minerals in place – net		348,608				–				46,178
	Sale of minerals in place – net		(252		)		(807		)		(1,124		)
	Revisions of previous quantity estimates		106,170				(876,336		)		(356,830		)
	Accretion of discount		343,502				622,072				478,165
	Net change in income taxes		(1,031,105		)		1,127,272				(560,360		)
	Timing and other		554,159				111,000				622,127
	Net increase (decrease)		1,796,120				(1,777,665		)		874,612
	Beginning of year		2,155,159				3,932,824				3,058,212
	End of year		$	3,951,279			$	2,155,159			$	3,932,824

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details) (EQT Midstream Partners, LP)	0 Months Ended		12 Months Ended
	Jul. 22, 2013	Jul. 02, 2012	Dec. 31, 2013	Dec. 31, 2013
			General partner	Limited partner
Principles of Consolidation	'	'	'	'
Ownership percentage	44.60%	59.40%	2.00%	42.60%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item
Summary of Significant Accounting Policies	'	'	'
Equity method ownership percentage	50.00%	'	'
Number of reportable segments	2	'	'
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	$400,000	$7,000,000	$7,200,000
Oil and gas producing properties, successful efforts method	8,152,951,000	6,750,343,000	5,772,083,000
Accumulated depletion	-2,134,953,000	-1,572,775,000	-1,177,526,000
Net capitalized costs	6,017,998,000	5,177,568,000	4,594,557,000
Property, Plant and Equipment:	'	'	'
Property, plant and equipment	11,062,136,000	9,153,207,000	'
Accumulated depreciation and amortization	-2,728,374,000	-2,093,795,000	'
Net property, plant and equipment	8,333,762,000	7,059,412,000	'
Capitalized internal costs of oil and gas producing properties under the successful efforts method	93,500,000	72,100,000	69,300,000
Capitalized interest costs	22,900,000	15,600,000	13,300,000
Depletion rate of oil and gas producing properties under successful efforts method (in dollars per Mcfe)	1.5	1.52	1.25
Capitalized costs of undeveloped properties	450,200,000	385,600,000	'
Undeveloped property impairments	14,200,000	5,500,000	2,600,000
Deferred taxes related to regulatory assets	13,300,000	18,300,000	'
EQT Midstream	'	'	'
Property, Plant and Equipment:	'	'	'
Property, plant and equipment	2,807,165,000	2,308,362,000	'
Accumulated depreciation and amortization	-547,991,000	-483,358,000	'
Net property, plant and equipment	2,259,174,000	1,825,004,000	'
Other Properties	'	'	'
Property, Plant and Equipment:	'	'	'
Net property, plant and equipment	$56,590,000	$56,840,000	'

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Proved Wells	'	'
Capitalized exploratory well costs pending the determination of proved reserves	$0	$0

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
EQT Midstream	'	'	'
Property Net Revenue and Operating Expense	'	'	'
Total regulated net revenues	$184,767	$131,184	$113,774
Total regulated operating expenses	$71,517	$66,202	$76,247
Gathering and transmission systems | Minimum	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'25 years	'	'
Gathering and transmission systems | Maximum	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'60 years	'	'
Building	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'35 years	'	'
Office equipment | Minimum	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'3 years	'	'
Office equipment | Maximum	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'7 years	'	'
Vehicles	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'5 years	'	'
Computer and telecommunications equipment and systems | Minimum	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'3 years	'	'
Computer and telecommunications equipment and systems | Maximum	'	'	'
Property, Plant and Equipment:	'	'	'
Estimated service life	'7 years	'	'

Summary_of_Significant_Account7

Summary of Significant Accounting Policies (Details 5) (USD $)	12 Months Ended					0 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Jul. 22, 2013	Jul. 02, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
				Minimum	Maximum	EQT Midstream Partners, LP	EQT Midstream Partners, LP	General partner	Limited partner	EQT Midstream	EQT Midstream
								EQT Midstream Partners, LP	EQT Midstream Partners, LP
Regulated Property, Plant and Equipment	'	'	'	'	'	'	'	'	'	'	'
Regulated property, plant and equipment, gross	'	'	'	'	'	'	'	'	'	$1,015,118,000	$797,405,000
Regulated accumulated depreciation and amortization	'	'	'	'	'	'	'	'	'	-158,533,000	-143,714,000
Regulated property, plant and equipment, net	'	'	'	'	'	'	'	'	'	856,585,000	653,691,000
Capitalized interest cost as part of allowance for funds used during construction	4,300,000	3,900,000	2,200,000	'	'	'	'	'	'	'	'
AFUDC equity amounts capitalized	1,200,000	6,800,000	3,800,000	'	'	'	'	'	'	'	'
Other Current Liabilities:	'	'	'	'	'	'	'	'	'	'	'
Incentive compensation	65,053,000	52,291,000	'	'	'	'	'	'	'	'	'
Taxes other than income	39,073,000	37,048,000	'	'	'	'	'	'	'	'	'
Accrued interest payable	29,379,000	29,878,000	'	'	'	'	'	'	'	'	'
All other accrued liabilities	18,763,000	27,388,000	'	'	'	'	'	'	'	'	'
Total other current liabilities	152,268,000	146,605,000	'	'	'	'	'	'	'	'	'
Ownership percentage	'	'	'	'	'	44.60%	59.40%	2.00%	42.60%	'	'
Ownership percentage used in applying equity method of accounting	'	'	'	20.00%	50.00%	'	'	'	'	'	'
Tax benefit recognized in financial statements, percentage threshold	50.00%	'	'	'	'	'	'	'	'	'	'
Asset retirement obligations	'	'	'	'	'	'	'	'	'	'	'
Asset retirement obligation as of beginning of period	109,034,000	102,439,000	'	'	'	'	'	'	'	'	'
Accretion expense	8,342,000	7,716,000	'	'	'	'	'	'	'	'	'
Liabilities incurred	2,510,000	1,141,000	'	'	'	'	'	'	'	'	'
Liabilities settled	-3,353,000	-2,408,000	'	'	'	'	'	'	'	'	'
Revisions in estimated cash flows	-488,000	146,000	'	'	'	'	'	'	'	'	'
Asset retirement obligation as of end of period	116,045,000	109,034,000	102,439,000	'	'	'	'	'	'	'	'
Accumulated other comprehensive income:	'	'	'	'	'	'	'	'	'	'	'
Net unrealized gain from natural gas hedging transactions	61,699,000	138,188,000	'	'	'	'	'	'	'	'	'
Net unrealized loss from interest rate swaps	-1,132,000	-1,276,000	'	'	'	'	'	'	'	'	'
Pension and other post-retirement benefits liability adjustment	-15,864,000	-37,365,000	'	'	'	'	'	'	'	'	'
Accumulated OCI	$44,703,000	$99,547,000	'	'	'	'	'	'	'	'	'

Discontinued_Operations_Detail

Discontinued Operations (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 17, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Equitable Gas and Homeworks

Equitable Gas and Homeworks

Equitable Gas and Homeworks

Equitable Gas and Homeworks

Equitable Gas and Homeworks

Equitable Gas and Homeworks

EQT Midstream

EQT Midstream

EQT Midstream

Discontinued operations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interests of Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (Homeworks) to PNG Companies

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

Cash payment received

'

'

'

'

'

'

'

'

'

'

'

$740,600,000

'

'

'

'

'

Preliminary estimated fair value of consideration received

'

'

'

'

'

'

'

'

'

'

'

141,400,000

'

'

'

'

'

Preliminary estimated fair value of other contractual assets received as consideration

'

'

'

'

'

'

'

'

'

'

'

32,500,000

'

'

'

'

'

Lease rent receivable per year

'

'

'

'

'

'

'

'

'

'

'

2,500,000

'

'

'

'

'

Period for which lease rent will be received

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

Lease receivable, net of unearned interest

'

'

'

'

'

'

'

'

'

'

'

'

19,700,000

'

'

'

'

Intangible assets resulted from other contractual agreements acquired

'

'

'

'

'

'

'

'

'

'

'

12,800,000

'

'

'

'

'

Value of energy marketing contracts

'

'

'

'

'

'

'

'

'

'

'

5,000,000

'

'

'

'

'

Amortization period of remaining contract-based intangible

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

Gain on sale of business

'

'

'

'

'

'

'

'

'

'

'

43,800,000

'

'

'

'

'

Income from discontinued operations, net of tax

'

'

'

'

'

'

'

'

'

'

'

122,500,000

'

'

'

'

'

Equitable Gas transaction costs

'

'

'

'

'

'

'

'

'

'

'

'

8,100,000

4,500,000

'

'

'

Write off of income tax related regulatory assets

'

'

'

'

'

'

'

'

'

'

'

'

51,600,000

'

'

'

'

Period of long-term commercial arrangements with PNG Companies and its affiliates

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

Intra-entity revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,600,000

36,800,000

37,900,000

Summary of the discontinued operations activity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

332,947,000

314,821,000

420,563,000

'

'

'

'

'

'

Income from discontinued operations before income taxes

'

'

'

'

'

'

'

'

251,378,000

81,328,000

101,010,000

'

'

'

'

'

'

Income taxes

'

'

'

'

'

'

'

'

159,535,000

33,835,000

40,823,000

'

'

'

'

'

'

Income from discontinued operations, net of tax

53,272,000

2,057,000

5,390,000

31,124,000

14,918,000

2,863,000

6,144,000

23,568,000

91,843,000

47,493,000

60,187,000

'

'

'

'

'

'

Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts receivable and unbilled receivables

'

'

'

'

42,919,000

'

'

'

'

42,919,000

'

'

'

'

'

'

'

Inventory

'

'

'

'

31,622,000

'

'

'

'

31,622,000

'

'

'

'

'

'

'

Other current assets

'

'

'

'

18,137,000

'

'

'

'

18,137,000

'

'

'

'

'

'

'

Total current assets

'

'

'

'

92,678,000

'

'

'

'

92,678,000

'

'

'

'

'

'

'

Property, plant and equipment, net

'

'

'

'

655,886,000

'

'

'

'

655,886,000

'

'

'

'

'

'

'

Regulatory assets

'

'

'

'

93,599,000

'

'

'

'

93,599,000

'

'

'

'

'

'

'

Other assets

'

'

'

'

571,000

'

'

'

'

571,000

'

'

'

'

'

'

'

Total noncurrent assets

'

'

'

'

750,056,000

'

'

'

'

750,056,000

'

'

'

'

'

'

'

Assets of discontinued operations

'

'

'

'

842,734,000

'

'

'

'

842,734,000

'

'

'

'

'

'

'

Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts payable

'

'

'

'

12,230,000

'

'

'

'

12,230,000

'

'

'

'

'

'

'

Accrued customer credits

'

'

'

'

32,376,000

'

'

'

'

32,376,000

'

'

'

'

'

'

'

Other current liabilities

'

'

'

'

3,685,000

'

'

'

'

3,685,000

'

'

'

'

'

'

'

Total current liabilities

'

'

'

'

48,291,000

'

'

'

'

48,291,000

'

'

'

'

'

'

'

Deferred income taxes

'

'

'

'

223,959,000

'

'

'

'

223,959,000

'

'

'

'

'

'

'

Pension and other post-retirement benefits

'

'

'

'

27,985,000

'

'

'

'

27,985,000

'

'

'

'

'

'

'

Other liabilities

'

'

'

'

5,671,000

'

'

'

'

5,671,000

'

'

'

'

'

'

'

Total noncurrent liabilities

'

'

'

'

257,615,000

'

'

'

'

257,615,000

'

'

'

'

'

'

'

Liabilities of discontinued operations

'

'

'

'

$305,906,000

'

'

'

'

$305,906,000

'

'

'

'

'

'

'

EQT_Midstream_Partners_LP_Deta

EQT Midstream Partners, LP (Details) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jul. 02, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jul. 02, 2012

Jul. 02, 2012

Jul. 22, 2013

Jul. 02, 2012

Dec. 31, 2013

Dec. 31, 2012

Performance awards

Performance awards

Performance awards

Phantom units

Phantom units

Line of credit

Equitrans

EQT Midstream Partners

EQT Midstream Partners

EQT Midstream Partners

EQT Midstream Partners

Subsidiary or equity method investee

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of common units issued to the public in an offering (in shares)

'

'

'

'

'

'

'

'

'

'

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)

'

'

'

'

'

'

'

'

'

'

3,443,902

2,964,718

'

'

Subordinated units (in shares)

'

'

'

'

'

'

'

'

'

'

17,339,718

17,339,718

'

'

General partner's interest (as a percent)

'

'

'

'

'

'

'

'

'

'

2.00%

2.00%

'

'

Percentage of ownership contributed

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

Additional borrowing

'

'

'

'

'

'

'

'

$350,000,000

'

'

'

'

'

Reversal of net deferred tax liability

5,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of shares granted

'

'

'

146,490

146,490

142,500

3,790

4,780

'

'

'

'

'

'

Proceeds from offerings, net of underwriters' discount and estimated offering expenses

529,442,000

276,780,000

'

'

'

'

'

'

'

'

529,400,000

277,000,000

'

'

Portion of proceeds from IPO that are distributed to parent

'

'

'

'

'

'

'

'

'

'

'

231,000,000

'

'

Amount retained to replenish amounts distributed by Equitrans to EQT

'

'

'

'

'

'

'

'

'

'

'

12,000,000

'

'

Amount retained to pre-fund maintenance capital expenditures

'

'

'

'

'

'

'

'

'

'

'

32,000,000

'

'

Payment of revolving credit facility origination fees

'

4,022,000

11,738,000

'

'

'

'

'

'

'

'

2,000,000

'

'

Offering expenses

'

'

'

'

'

'

'

'

'

'

20,900,000

'

'

'

Net income attributable to noncontrolling interests

47,243,000

13,016,000

'

'

'

'

'

'

'

'

'

'

47,200,000

13,000,000

Distributions paid to noncontrolling interest

$32,781,000

$5,031,000

'

'

'

'

'

'

'

'

'

'

$32,800,000

$5,000,000

Distributions to noncontrolling interests (in dollars per common unit)

$1.55

$0.35

'

'

'

'

'

'

'

'

'

'

$1.55

$0.35

Financial_Information_by_Busin2

Financial Information by Business Segment (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating segments information	'	'	'	'	'	'	'	'	'	'	'
Revenues from external customers	$493,429,000	$479,606,000	$473,093,000	$415,883,000	$406,273,000	$337,916,000	$298,742,000	$334,291,000	$1,862,011,000	$1,377,222,000	$1,323,829,000
Operating income	181,081,000	167,064,000	161,980,000	144,479,000	126,505,000	81,253,000	70,817,000	111,054,000	654,604,000	389,629,000	761,171,000
Reconciliation of operating income to income from continuing operations:	'	'	'	'	'	'	'	'	'	'	'
Other income	'	'	'	'	'	'	'	'	9,242,000	15,536,000	33,276,000
Interest expense	'	'	'	'	'	'	'	'	142,688,000	184,786,000	136,328,000
Income taxes	'	'	'	'	'	'	'	'	175,186,000	71,461,000	238,537,000
Income from continuing operations	'	'	'	'	'	'	'	'	345,972,000	148,918,000	419,582,000
Gains (Losses) on dispositions	'	'	'	'	'	'	'	'	19,618,000	'	202,928,000
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	653,132,000	474,617,000	313,868,000
Expenditure for segment assets	'	'	'	'	'	'	'	'	1,796,876,000	1,370,640,000	1,335,581,000
Expenditure on segment assets for the acquisition of producing properties	'	'	'	'	'	'	'	'	'	'	92,600,000
EQT Midstream	'	'	'	'	'	'	'	'	'	'	'
Reconciliation of operating income to income from continuing operations:	'	'	'	'	'	'	'	'	'	'	'
Gains (Losses) on dispositions	'	'	'	'	'	'	'	'	19,600,000	'	202,900,000
Operating segments | EQT Production	'	'	'	'	'	'	'	'	'	'	'
Operating segments information	'	'	'	'	'	'	'	'	'	'	'
Revenues from external customers	'	'	'	'	'	'	'	'	1,168,657,000	793,773,000	791,285,000
Operating income	'	'	'	'	'	'	'	'	371,245,000	187,913,000	387,098,000
Reconciliation of operating income to income from continuing operations:	'	'	'	'	'	'	'	'	'	'	'
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	578,641,000	409,628,000	257,144,000
Expenditure for segment assets	'	'	'	'	'	'	'	'	1,423,185,000	991,775,000	1,087,840,000
Expenditures for segment assets for property acquisitions	186,200,000	'	'	'	134,600,000	'	'	'	186,200,000	134,600,000	57,200,000
Expenditure on segment assets for the acquisition of producing properties	'	'	'	'	'	'	'	'	'	'	92,600,000
Operating segments | EQT Midstream	'	'	'	'	'	'	'	'	'	'	'
Operating segments information	'	'	'	'	'	'	'	'	'	'	'
Revenues from external customers	'	'	'	'	'	'	'	'	614,042,000	505,498,000	525,345,000
Operating income	'	'	'	'	'	'	'	'	328,782,000	237,324,000	416,611,000
Reconciliation of operating income to income from continuing operations:	'	'	'	'	'	'	'	'	'	'	'
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	75,032,000	64,782,000	57,135,000
Expenditure for segment assets	'	'	'	'	'	'	'	'	369,399,000	375,731,000	242,886,000
Less intersegment revenues, net	'	'	'	'	'	'	'	'	'	'	'
Operating segments information	'	'	'	'	'	'	'	'	'	'	'
Revenues from external customers	'	'	'	'	'	'	'	'	-62,969,000	-48,832,000	-79,835,000
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	37,900,000
Intercompany eliminations for retail business activity	'	'	'	'	'	'	'	'	2,600,000	11,700,000	64,500,000
Third-party transportation costs	'	'	'	'	'	'	'	'	'	'	'
Operating segments information	'	'	'	'	'	'	'	'	'	'	'
Revenues from external customers	'	'	'	'	'	'	'	'	142,281,000	126,783,000	87,034,000
Unallocated expenses and Other	'	'	'	'	'	'	'	'	'	'	'
Operating segments information	'	'	'	'	'	'	'	'	'	'	'
Operating income	'	'	'	'	'	'	'	'	-45,423,000	-35,608,000	-42,538,000
Reconciliation of operating income to income from continuing operations:	'	'	'	'	'	'	'	'	'	'	'
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	-541,000	207,000	-411,000
Expenditure for segment assets	'	'	'	'	'	'	'	'	$4,292,000	$3,134,000	$4,855,000

Financial_Information_by_Busin3

Financial Information by Business Segment (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Operating segments information	'	'	'
Total assets	$9,792,053	$8,849,862	'
Operating segments	'	'	'
Operating segments information	'	'	'
Total assets	8,873,494	7,722,092	'
Operating segments | EQT Production	'	'	'
Operating segments information	'	'	'
Total assets	6,359,065	5,675,534	5,256,600
Operating segments | EQT Midstream	'	'	'
Operating segments information	'	'	'
Total assets	2,514,429	2,046,558	1,785,100
Headquarters	'	'	'
Operating segments information	'	'	'
Total assets	$918,559	$1,127,770	'

Derivative_Instruments_Details

Derivative Instruments (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivatives designated as hedging instruments	'	'	'	'	'	'	'	'	'	'	'
Net of tax amount included in OCI	($1,132,000)	'	'	'	($1,276,000)	'	'	'	($1,132,000)	($1,276,000)	'
Natural Gas Hedging Instruments	'	'	'	'	'	'	'	'	'	'	'
Deferred net gains in accumulated other comprehensive income (loss), net of tax	61,700,000	'	'	'	138,200,000	'	'	'	61,700,000	138,200,000	'
Net unrealized gains on derivative commodity instruments	27,200,000	'	'	'	'	'	'	'	27,200,000	'	'
Margin deposits with brokers	300,000	'	'	'	700,000	'	'	'	300,000	700,000	'
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	8,800,000	'	'	'	'	'	'	'	8,800,000	'	'
Collateral posted	0	'	'	'	'	'	'	'	0	'	'
Reduction in operating revenue	493,429,000	479,606,000	473,093,000	415,883,000	406,273,000	337,916,000	298,742,000	334,291,000	1,862,011,000	1,377,222,000	1,323,829,000
Increase of accumulated OCI	'	'	'	'	'	'	'	'	-54,844,000	-88,594,000	150,037,000
Correction of error related to the accounting for a derivative instrument put premium	'	'	'	'	'	'	'	'	'	'	'
Natural Gas Hedging Instruments	'	'	'	'	'	'	'	'	'	'	'
Increase of accumulated OCI	'	'	'	'	'	'	5,100,000	'	'	'	'
Decrease of deferred tax expense	'	'	'	'	'	'	3,100,000	'	'	'	'
Correction of error related to the accounting for a derivative instrument put premium | EQT Production segment	'	'	'	'	'	'	'	'	'	'	'
Natural Gas Hedging Instruments	'	'	'	'	'	'	'	'	'	'	'
Reduction in operating revenue	'	'	'	'	'	'	-8,200,000	'	'	'	'
Interest rate swaps settled	'	'	'	'	'	'	'	'	'	'	'
Derivatives designated as hedging instruments	'	'	'	'	'	'	'	'	'	'	'
Amount of gain (loss) recognized in OCI (effective portion), net of tax	'	'	'	'	'	'	'	'	'	'	-1,400,000
Number of swaps settled	'	'	'	'	'	'	'	'	'	'	1
Term over which loss is recorded in OCI to be recognized	'	'	'	'	'	'	'	'	'	'	'10 years
Interest rate swaps	'	'	'	'	'	'	'	'	'	'	'
Derivatives designated as hedging instruments	'	'	'	'	'	'	'	'	'	'	'
Amount of gain (loss) recognized in OCI (effective portion), net of tax	'	'	'	'	'	'	'	'	'	7,100,000	'
Amount of gain (loss) 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	'	'	'	'	13,300,000	'
Number of forward-starting interest rate swaps entered into by the entity	'	'	'	'	'	'	'	'	'	'	2
Net of tax amount included in OCI	'	'	'	'	'	'	'	'	'	'	6,200,000
Commodity derivatives	'	'	'	'	'	'	'	'	'	'	'
Natural Gas Hedging Instruments	'	'	'	'	'	'	'	'	'	'	'
Absolute quantities of derivative commodity instruments that have been designated and qualify as cash flow or fair value hedges (in Bcf)	'	'	'	'	'	'	'	'	'	8,000	'
Margin deposits with brokers	266,000	'	'	'	736,000	'	'	'	266,000	736,000	'
Cash flow hedges | Interest rate derivatives	'	'	'	'	'	'	'	'	'	'	'
Derivatives designated as hedging instruments	'	'	'	'	'	'	'	'	'	'	'
Amount of gain (loss) recognized in OCI (effective portion), net of tax	'	'	'	'	'	'	'	'	'	-7,138,000	-7,573,000
Amount of (loss) reclassified from accumulated OCI, net of tax, into interest expense due to forecasted transactions no longer being probable	'	'	'	'	'	'	'	'	'	-13,266,000	'
Amount of gain (loss) reclassified from accumulated OCI, net of tax into operating revenues (effective portion)	'	'	'	'	'	'	'	'	-144,000	-241,000	-140,000
Cash flow hedges | Commodity derivatives	'	'	'	'	'	'	'	'	'	'	'
Derivatives designated as hedging instruments	'	'	'	'	'	'	'	'	'	'	'
Pre-tax gain recognized in operating revenues for de-designation of derivative instruments related to sale of certain energy marketing contracts	'	'	'	'	'	'	'	'	1,000,000	'	'
Amount of gain (loss) recognized in OCI (effective portion), net of tax	'	'	'	'	'	'	'	'	10,669,000	86,259,000	239,019,000
Amount of gain (loss) reclassified from accumulated OCI, net of tax into operating revenues (effective portion)	'	'	'	'	'	'	'	'	87,158,000	180,137,000	72,179,000
Amount of (loss) recognized in operating revenues (ineffective portion)	'	'	'	'	'	'	'	'	-21,335,000	-75,000	-181,000
Natural Gas Hedging Instruments	'	'	'	'	'	'	'	'	'	'	'
Absolute quantities of derivative commodity instruments that have been designated and qualify as cash flow or fair value hedges (in Bcf)	'	'	'	'	'	'	'	'	398,000	365,000	'
Fair value hedges | Commodity derivatives	'	'	'	'	'	'	'	'	'	'	'
Derivatives designated as hedging instruments	'	'	'	'	'	'	'	'	'	'	'
Amount of (loss) gain recognized in operating revenues for fair value commodity contracts	'	'	'	'	'	'	'	'	-1,341,000	3,878,000	12,263,000
Fair value (loss) gain recognized in operating revenues for inventory designated as hedged item	'	'	'	'	'	'	'	'	386,000	3,292,000	-6,059,000
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	7,600,000
Amount of gain (loss) recognized in income due to changes in basis	'	'	'	'	'	'	'	'	-1,500,000	-400,000	-1,400,000
Not designated as hedging instruments	'	'	'	'	'	'	'	'	'	'	'
Derivatives not designated as hedging instruments:	'	'	'	'	'	'	'	'	'	'	'
Amount of (loss) gain recognized in operating revenues	'	'	'	'	'	'	'	'	$2,834,000	$2,176,000	$4,209,000

Derivative_Instruments_Details1

Derivative Instruments (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Asset and liability derivatives	'	'
Derivatives designated as hedging instruments	$107,647	$304,237
Derivatives designated as hedging instruments	29,651	75,562
Commodity contracts	'	'
Asset and liability derivatives	'	'
Derivatives designated as hedging instruments	107,647	304,237
Derivatives designated as hedging instruments	29,651	75,562
Commodity derivatives designated as hedging instruments | Commodity contracts	'	'
Asset and liability derivatives	'	'
Derivatives designated as hedging instruments	104,430	259,459
Derivatives designated as hedging instruments	27,618	27,946
Commodity derivatives not designated as hedging instruments | Commodity contracts	'	'
Asset and liability derivatives	'	'
Derivatives designated as hedging instruments	3,217	44,778
Derivatives designated as hedging instruments	$2,033	$47,616

Derivative_Instruments_Details2

Derivative Instruments (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Asset derivatives:	'	'
Derivative instruments, at fair value	$107,647	$304,237
Liability derivatives:	'	'
Derivative instruments, at fair value	29,651	75,562
Margin deposits received (remitted to) counterparties	-300	-700
Commodity derivatives	'	'
Asset derivatives:	'	'
Derivative instruments, at fair value	107,647	304,237
Derivative instruments subject to master netting agreements	-20,843	-73,753
Derivative instruments, net	86,804	230,484
Liability derivatives:	'	'
Derivative instruments, at fair value	29,651	75,562
Derivative instruments subject to master netting agreements	-20,843	-73,753
Margin deposits received (remitted to) counterparties	-266	-736
Derivative instruments, net	$8,542	$1,073

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements	'	'
Fair value derivative instruments Level 3 to Level 2 Transfers Amount	$54,400,000	'
Fair value on a recurring basis | Fair Value	'	'
Assets	'	'
Derivative instruments, at fair value	107,647,000	304,237,000
Liabilities	'	'
Derivative instruments, at fair value	29,651,000	75,562,000
Fair value on a recurring basis | Quoted prices in active markets for identical assets (Level 1)	'	'
Assets	'	'
Derivative instruments, at fair value	240,000	1,228,000
Liabilities	'	'
Derivative instruments, at fair value	315,000	1,609,000
Fair value on a recurring basis | Significant other observable inputs (Level 2)	'	'
Assets	'	'
Derivative instruments, at fair value	107,407,000	204,592,000
Liabilities	'	'
Derivative instruments, at fair value	29,336,000	66,250,000
Fair value on a recurring basis | Significant unobservable inputs (Level 3)	'	'
Assets	'	'
Derivative instruments, at fair value	'	98,417,000
Liabilities	'	'
Derivative instruments, at fair value	'	$7,703,000

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation	'	'
Estimated fair value of long-term debt	$2,800,000,000	$2,900,000,000
Derivative instruments, at fair value, net	'	'
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation	'	'
Balance at the beginning of the period	90,714,000	143,260,000
Total gains or losses included in earnings	640,000	-615,000
Total gains or losses included in OCI	-2,554,000	23,386,000
Purchases	'	-933,000
Settlements	-34,381,000	-74,384,000
Transfers in and/or out of Level 3	-54,419,000	'
Balance at the end of the period	'	90,714,000
Unrealized gains and losses included in earnings	$0	$0

Fair_Value_Measurements_Detail2

Fair Value Measurements (Details 3) (Equitable Gas and Homeworks, USD $)	Dec. 17, 2013
In Millions, unless otherwise specified
Fair value measurements	'
Preliminary estimated fair value of assets	$141.40
Preliminary estimated fair value of other contractual assets	32.5
Level 2 | Income approach models	'
Fair value measurements	'
Preliminary estimated fair value of assets	141.4
Preliminary estimated fair value of other contractual assets	$32.50

Sales_of_Properties_and_Contra1

Sales of Properties and Contracts (Details) (USD $)	12 Months Ended			0 Months Ended	12 Months Ended	1 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 17, 2013	Dec. 31, 2013	Feb. 28, 2011	Jul. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
				Equitable Gas and Homeworks	Equitable Gas and Homeworks	Langley	Big Sandy Pipeline	Lycoming County, Pennsylvania	Lycoming County, Pennsylvania	Westmoreland County, Pennsylvania
					MMcf			acre	acre	acre
					item
Equity in Nonconsolidated Investments	'	'	'	'	'	'	'	'	'	'
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	23,000,000	'	'	'	18,000,000	'	'	'	'	'
Amount expected to be collected	'	'	'	'	2,000,000	'	'	'	'	'
Gain on sale of energy marketing contracts	'	'	'	'	19,600,000	'	'	'	'	'
Pre-tax gain on sale of business	'	'	'	'	'	22,800,000	180,100,000	2,000,000	3,900,000	400,000
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	'	'	'	'	'
Net proceeds from sale of business	'	'	'	740,600,000	'	'	390,000,000	'	'	400,000
Size of land under sold leases (in acres)	'	'	'	'	'	'	'	2,900	2,900	128
Net proceeds after purchase price adjustments	$740,587,000	$4,842,000	$619,999,000	'	'	$230,000,000	'	$2,700,000	$6,000,000	'

Acquisitions_Details

Acquisitions (Details) (USD $)

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

4-May-11

Dec. 31, 2011

Jun. 03, 2013

Jun. 03, 2013

Dec. 31, 2013

4-May-11

Jun. 30, 2011

Dec. 31, 2000

4-May-11

Mcfe

7.76% notes, due 2012 thru 2016

7.76% notes, due 2012 thru 2016

Chesapeake

Chesapeake

Chesapeake

Appalachian Natural Gas Trust

Appalachian Natural Gas Trust

Appalachian Natural Gas Trust

Appalachian Natural Gas Trust

acre

Marcellus

Marcellus

Class A interest

item

Mcfe

acre

Acquisitions

'

'

'

'

'

'

'

'

'

'

'

'

Approximate area of acquisition (in acres)

'

'

'

'

'

99,000

67,000

'

'

'

'

'

Number of wells acquired

'

'

'

'

'

'

10

'

'

'

'

'

Purchase price of acquisition

'

'

'

'

'

$114,200,000

'

'

'

'

'

'

Purchase price of acquisition allocated to undeveloped acreage

95,861,000

117,654,000

41,085,000

'

'

57,200,000

'

'

'

'

'

'

Purchase price of acquisition allocated to acquired wells

90,390,000

16,965,000

108,717,000

'

'

'

57,000,000

57,000,000

'

'

'

'

Portion unlikely to be developed (in acres)

'

'

'

'

'

'

42,000

'

'

'

'

'

Addition in sales volume (in Bcfe)

'

'

'

'

'

'

1,700,000

'

'

'

'

'

Acquisition of proved developed reserves (Bcfe)

39,700,000

'

'

'

'

'

53,500,000

'

'

'

'

'

Proceeds from sale of net profits interest (NPI) in certain producing properties

'

'

'

'

'

'

'

'

'

'

298,000,000

'

Percentage of net profits received by ANGT

'

'

'

'

'

'

'

'

'

'

100.00%

'

Ownership percentage

'

'

'

'

'

'

'

'

'

'

'

100.00%

Debt instrument, stated interest rate percentage

'

'

'

'

7.76%

'

'

'

'

'

'

'

Additional borrowing

'

'

'

57,100,000

'

'

'

'

'

'

'

'

Fair value of notes

2,800,000,000

2,900,000,000

'

64,200,000

'

'

'

'

'

'

'

'

Pre-tax gain on revaluation of existing equity investment in acquiree

'

'

'

'

'

'

'

'

'

10,100,000

'

'

Derecognition of post revaluation of oil and gas properties

'

'

'

'

'

'

'

'

140,600,000

'

'

'

Derecognition of post revaluation of equity investment in ANGT

'

'

'

'

'

'

'

'

48,000,000

'

'

'

Net increase in liabilities

'

'

'

'

'

'

'

'

92,600,000

'

'

'

Liability for discounted sales

'

'

'

'

'

'

'

'

16,400,000

'

'

'

Recognition of a derivative liability for swap

'

'

'

'

'

'

'

'

$12,700,000

'

'

'

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:	'	'	'
Federal	$100,796	$3,771	$30,837
State	46,758	229	1,434
Subtotal	147,554	4,000	32,271
Deferred:	'	'	'
Federal	51,767	56,551	177,474
State	-23,940	11,014	29,003
Subtotal	27,827	67,565	206,477
Amortization of deferred investment tax credit	-195	-104	-211
Income tax expense	$175,186	$71,461	$238,537
Deduction of intangible drilling costs (as a percent)	83.00%	'	'

Income_Taxes_Details_2

Income Taxes (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes	'	'	'
Federal statutory rate (as a percent)	35.00%	'	'
Tax at statutory rate	$182,406,000	$77,133,000	$230,342,000
State income taxes	16,180,000	2,869,000	18,150,000
Federal tax credits and incentives	-750,000	-439,000	-660,000
Permanent basis differences	-407,000	-2,789,000	-2,020,000
Noncontrolling partners' share of Partnership earnings	-16,535,000	-4,571,000	'
Other	-5,708,000	-742,000	-7,275,000
Income tax expense	175,186,000	71,461,000	238,537,000
Effective tax rate (as a percent)	33.60%	32.40%	36.20%
State tax benefits offsetting income tax	$9,800,000	'	'
Percentage of consolidated pre-tax income related to the noncontrolling public limited partners' share of partnership earnings	100.00%	100.00%	'

Income_Taxes_Details_3

Income Taxes (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of reserve for uncertain tax positions, Excluding Amounts Pertaining to Examined Tax Returns	'	'	'
Reserve for uncertain tax positions (excluding interest and penalties) at the beginning of the period	$17,858,000	$30,730,000	$37,943,000
Additions based on tax positions related to current year	49,289,000	2,165,000	1,245,000
Additions for tax positions of prior years	'	2,320,000	184,000
Reductions for tax positions of prior years	-790,000	-12,235,000	-7,886,000
Lapse of statute of limitations	-9,270,000	-5,122,000	-756,000
Reserve for uncertain tax positions (excluding interest and penalties) at the end of the period	57,087,000	17,858,000	30,730,000
Tax deductible, but uncertainty about the timing of deductibility	7,600,000	6,400,000	15,900,000
Decrease in unrecognized tax benefits	9,800,000	14,600,000	'
Interest expense (reversal)	500,000	1,800,000	9,700,000
Interest and penalties included in balance sheet	200,000	500,000	2,300,000
Unrecognized tax benefits that would impact effective tax rate	$33,300,000	$5,300,000	$5,200,000

Income_Taxes_Details_4

Income Taxes (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred income taxes:	'	'	'
Total deferred income tax assets	($670,368,000)	($696,252,000)	'
Total deferred income tax liabilities	2,295,128,000	2,122,377,000	'
Total net deferred income tax liabilities	1,624,760,000	1,426,125,000	'
Total deferred income tax liabilities (assets)	'	'	'
Drilling and development costs expensed for income tax reporting	1,181,375,000	933,800,000	'
Tax depreciation in excess of book depreciation	923,443,000	924,229,000	'
Investment in Partnership	101,569,000	108,764,000	'
Accumulated OCI	28,597,000	81,087,000	'
Post-retirement benefits	-3,946,000	-3,784,000	'
Incentive compensation	-60,982,000	-28,811,000	'
Alternative minimum tax credit carryforward	-246,157,000	-69,901,000	'
Net operating loss carryforwards	-359,283,000	-593,756,000	'
Other	3,740,000	8,261,000	'
Total excluding valuation allowances	1,568,356,000	1,359,889,000	'
Valuation allowance	56,404,000	66,236,000	'
Total (including amounts classified as current assets of $31,005 and $15,946, respectively)	1,624,760,000	1,426,125,000	'
Current deferred income tax assets	31,005,000	15,946,000	'
Deferred assets/(liability) related to net unrealized income/loss from hedging transactions	38,700,000	88,800,000	'
Deferred tax asset related to other post-retirement benefits	5,300,000	3,600,000	'
Deferred tax asset related to pension plans	4,800,000	4,100,000	'
Total deferred tax asset related to the federal NOL carryforward	183,200,000	'	'
Deferred tax asset related to NOL carryforward	'	166,100,000	17,100,000
Increase (decrease) in deferred tax asset for uncertain tax positions related to federal operating loss carryforwards	10,600,000	-3,700,000	'
NOL carryforward period	'	'20 years	'20 years
Deferred tax asset for state NOL carryforwards	118,200,000	86,000,000	'
Reduction in deferred tax asset for uncertain tax positions related to state NOL carryforwards	500,000	500,000	'
Valuation allowance pertaining to NOL carryforwards	56,400,000	66,200,000	'
Excess tax benefit	'	8,100,000	6,600,000
Tax benefits recognized as an addition to common stockholders' equity	$12,200,000	'	'

Equity_in_Nonconsolidated_Inve2

Equity in Nonconsolidated Investments (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity in Nonconsolidated Investments	'	'	'
Equity in nonconsolidated investments	$128,983,000	$130,368,000	'
Equity in earnings of nonconsolidated investments	7,600,000	6,100,000	7,200,000
Summarized Balance Sheets	'	'	'
Current assets	27,014,000	15,966,000	'
Noncurrent assets	239,583,000	249,347,000	'
Total assets	266,597,000	265,313,000	'
Current liabilities	8,529,000	4,476,000	'
Stockholders' equity	258,068,000	260,837,000	'
Total liabilities and stockholders' equity	266,597,000	265,313,000	'
Summarized Statements of Income	'	'	'
Revenues	45,040,000	47,888,000	49,772,000
Operating expenses	29,810,000	35,596,000	35,520,000
Net income	15,230,000	12,292,000	14,252,000
Nora Gathering, LLC	'	'	'
Equity in Nonconsolidated Investments	'	'	'
Ownership percentage	50.00%	'	'
Equity in nonconsolidated investments	128,983,000	130,368,000	'
Nora Gathering, LLC | EQT Midstream	'	'	'
Equity in Nonconsolidated Investments	'	'	'
Ownership percentage	50.00%	'	'
Additional equity investments made	$0	$0	'

ShortTerm_Loans_Details

Short-Term Loans (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item
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	16	'	'
Commitment fee paid to maintain credit facility (as a percent)	0.24%	0.25%	'
Maximum amount of outstanding short-term loans at any time during the period	178,500,000	'	104,000,000
Average daily balance of short-term loans outstanding during the period	12,100,000	'	5,500,000
Weighted average interest rates of average daily balance of short-term loans (as a percent)	1.67%	'	1.81%
Percentage of total debt to total capital, maximum	65.00%	'	'
Revolving credit facility outstanding amount at the end of period	0	0	'
EQT Midstream Partners	'	'	'
Line of Credit Facility	'	'	'
Revolving credit facility maximum borrowing capacity	350,000,000	'	'
Commitment fee paid to maintain credit facility (as a percent)	0.25%	0.25%	'
Maximum amount of outstanding short-term loans at any time during the period	0	0	'
Revolving credit facility outstanding amount at the end of period	$0	$0	'

ShortTerm_Loans_Details_2

Short-Term Loans (Details 2) (EQT Midstream Partners, Line of credit)	Dec. 31, 2013
EQT Midstream Partners | Line of credit	'
Short-Term Loans	'
Consolidated leverage ratio before obtaining investment grade rating	5
Consolidated leverage ratio after obtaining investment grade rating	5.5
Consolidated interest coverage ratio, until obtaining an investment grade rating	3

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Long term debt	'	'
Long-term debt	$2,501,516,000	$2,526,173,000
Less debt payable within one year	11,162,000	23,204,000
Total long-term debt	2,490,354,000	2,502,969,000
Aggregate maturities in 2014	11,200,000	'
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	'
7.76% notes, due 2014 thru 2016	'	'
Long term debt	'	'
Long-term debt	18,316,000	32,973,000
Debt instrument, stated interest rate percentage	7.76%	7.76%
5.00% notes, due October 1, 2015	'	'
Long term debt	'	'
Long-term debt	150,000,000	150,000,000
Debt instrument, stated interest rate percentage	5.00%	5.00%
5.15% notes, due March 1, 2018	'	'
Long term debt	'	'
Long-term debt	200,000,000	200,000,000
Debt instrument, stated interest rate percentage	5.15%	5.15%
6.50% notes, due April 1, 2018	'	'
Long term debt	'	'
Long-term debt	500,000,000	500,000,000
Debt instrument, stated interest rate percentage	6.50%	6.50%
8.13% notes, due June 1, 2019	'	'
Long term debt	'	'
Long-term debt	700,000,000	700,000,000
Debt instrument, stated interest rate percentage	8.13%	8.13%
4.88% notes, due November 15, 2021	'	'
Long term debt	'	'
Long-term debt	750,000,000	750,000,000
Debt instrument, stated interest rate percentage	4.88%	4.88%
7.75% debentures, due July 15, 2026	'	'
Long term debt	'	'
Long-term debt	115,000,000	115,000,000
Debt instrument, stated interest rate percentage	7.75%	7.75%
Medium-term notes, 8.7% to 9.0% Series A, due 2014 thru 2021	'	'
Long term debt	'	'
Long-term debt	40,200,000	40,200,000
Debt instrument, stated interest rate percentage minimum	8.70%	8.70%
Debt instrument, stated interest rate percentage maximum	9.00%	9.00%
Medium-term notes, 7.3% to 7.6% Series B, due 2015 thru 2023	'	'
Long term debt	'	'
Long-term debt	20,000,000	30,000,000
Debt instrument, stated interest rate percentage minimum	7.30%	7.30%
Debt instrument, stated interest rate percentage maximum	7.60%	7.60%
Medium-term notes, 7.6% Series C, due 2018	'	'
Long term debt	'	'
Long-term debt	$8,000,000	$8,000,000
Debt instrument, stated interest rate percentage	7.60%	7.60%

Pension_and_Other_PostRetireme2

Pension and Other Post-Retirement Benefit Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amounts recognized in accumulated OCI, net of tax, consist of:	'	'	'
Net amount recognized	$15,864,000	$37,365,000	'
Accumulated benefit obligation	21,800,000	20,400,000	'
Equitable Gas and Homeworks	'	'	'
Components of net periodic benefit cost:	'	'	'
Net loss and prior service cost	17,300,000	'	'
Pension Benefits	'	'	'
Change in benefit obligation:	'	'	'
Benefit obligation at beginning of year	63,270,000	61,885,000	'
Service cost	500,000	500,000	500,000
Interest cost	1,935,000	2,448,000	3,115,000
Amendments	'	-126,000	'
Actuarial loss	-3,038,000	5,733,000	'
Benefits paid	-5,269,000	-5,571,000	'
Expenses paid	-493,000	-511,000	'
Divestitures	-34,410,000	'	'
Settlements	-667,000	-1,088,000	'
Subtotal	21,828,000	63,270,000	61,885,000
Benefit obligation included in discontinued operations	'	42,835,000	'
Benefit obligation at end of year	21,828,000	20,435,000	'
Change in plan assets:	'	'	'
Fair value of plan assets at beginning of year	46,984,000	45,951,000	'
Actual gain on plan assets	7,304,000	5,346,000	'
Contributions	2,639,000	2,857,000	4,300,000
Benefits paid	-5,269,000	-5,571,000	'
Expenses paid	-493,000	-511,000	'
Divestitures	-30,409,000	'	'
Settlements	-667,000	-1,088,000	'
Subtotal	20,089,000	46,984,000	45,951,000
Fair value of plan assets included in discontinued operations	'	30,428,000	'
Fair value of plan assets at end of year	20,089,000	16,556,000	'
Funded status at end of year	-1,739,000	-3,879,000	'
Amounts recognized in the statement of financial position consist of:	'	'	'
Noncurrent liabilities	-1,739,000	-3,879,000	'
Net amounts recognized	-1,739,000	-3,879,000	'
Amounts recognized in accumulated OCI, net of tax, consist of:	'	'	'
Net loss	7,524,000	24,634,000	'
Net amount recognized	7,524,000	24,634,000	'
Components of net periodic benefit cost:	'	'	'
Service cost	500,000	500,000	500,000
Interest cost	1,935,000	2,448,000	3,115,000
Expected return on plan assets	-3,323,000	-3,712,000	-4,070,000
Recognized net actuarial loss	2,306,000	1,880,000	1,471,000
Settlement loss and special termination benefits	381,000	725,000	530,000
Subtotal	1,799,000	1,841,000	1,546,000
Net periodic benefit cost of discontinued operations	1,552,000	1,586,000	1,387,000
Net periodic benefit cost	247,000	255,000	159,000
Other Benefits	'	'	'
Change in benefit obligation:	'	'	'
Benefit obligation at beginning of year	36,255,000	35,293,000	'
Service cost	905,000	737,000	620,000
Interest cost	1,110,000	1,427,000	1,771,000
Actuarial loss	-2,355,000	2,656,000	'
Benefits paid	-3,961,000	-3,858,000	'
Divestitures	-13,701,000	'	'
Subtotal	18,253,000	36,255,000	35,293,000
Benefit obligation included in discontinued operations	'	15,577,000	'
Benefit obligation at end of year	18,253,000	20,678,000	'
Change in plan assets:	'	'	'
Fair value of plan assets at beginning of year	165,000	19,000	'
Contributions	328,000	146,000	'
Subtotal	493,000	165,000	19,000
Fair value of plan assets at end of year	493,000	165,000	'
Funded status at end of year	-17,760,000	-20,513,000	'
Amounts recognized in the statement of financial position consist of:	'	'	'
Current liabilities	-1,341,000	-3,353,000	'
Noncurrent liabilities	-16,419,000	-17,160,000	'
Net amounts recognized	-17,760,000	-20,513,000	'
Amounts recognized in accumulated OCI, net of tax, consist of:	'	'	'
Net loss	8,234,000	14,291,000	'
Net prior service (credit)	106,000	-1,560,000	'
Net amount recognized	8,340,000	12,731,000	'
Components of net periodic benefit cost:	'	'	'
Service cost	905,000	737,000	620,000
Interest cost	1,110,000	1,427,000	1,771,000
Amortization of prior service cost	-845,000	-845,000	-902,000
Recognized net actuarial loss	1,760,000	1,671,000	1,605,000
Subtotal	2,930,000	2,990,000	3,094,000
Net periodic benefit cost of discontinued operations	1,356,000	1,288,000	1,427,000
Net periodic benefit cost	$1,574,000	$1,702,000	$1,667,000

Pension_and_Other_PostRetireme3

Pension and Other Post-Retirement Benefit Plans (Details 2) (USD $)	0 Months Ended	12 Months Ended
	Jan. 02, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:	'	'	'	'
Total recognized in OCI, net of tax	'	($21,501,000)	$1,085,000	$4,474,000
Weighted average assumptions to determine the net periodic benefit cost	'	'	'	'
Annual rate of increase in Pre-65 medical charges (as a percent)	'	7.00%	'	'
Annual rate of increase in Post-65 medical charges (as a percent)	'	7.00%	'	'
Assumption for ultimate decrease in annual medical rates in 2018 (as a percent)	'	5.00%	'	'
Assumed health care cost trend rates on the amounts reported for the health care plans	'	'	'	'
Effect of a one-percentage-point increase to total of service and interest cost components	'	25,000	32,000	40,000
Effect of a one-percentage-point decrease to total of service and interest cost components	'	-26,000	-32,000	-39,000
Effect of a one-percentage-point increase to post-retirement benefit obligation	'	220,000	711,000	730,000
Effect of a one-percentage-point decrease to post-retirement benefit obligation	'	-223,000	-688,000	-702,000
Pension Benefits	'	'	'	'
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:	'	'	'	'
Net (gain) loss	'	712,000	261,000	3,378,000
Total recognized in OCI, net of tax	'	712,000	261,000	3,378,000
Total recognized in net periodic benefit cost and OCI, net of tax	'	959,000	2,102,000	4,924,000
Net loss of defined benefit pension plans, amortized from accumulated OCI, net of tax, into net periodic benefit cost	'	400,000	'	'
Weighted average assumptions to determine the benefit obligations	'	'	'	'
Discount rate, benefit obligations (as a percent)	'	4.00%	3.25%	'
Weighted average assumptions to determine the net periodic benefit cost	'	'	'	'
Discount rate, net periodic benefit (as a percent)	'	3.25%	4.25%	'
Expected return on plan assets (as a percent)	7.75%	7.75%	7.75%	'
Other Benefits	'	'	'	'
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:	'	'	'	'
Net (gain) loss	'	2,147,000	494,000	181,000
Net prior service cost	'	416,000	330,000	915,000
Total recognized in OCI, net of tax	'	2,563,000	824,000	1,096,000
Total recognized in net periodic benefit cost and OCI, net of tax	'	4,137,000	3,814,000	4,190,000
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	'	($300,000)	'	'
Weighted average assumptions to determine the benefit obligations	'	'	'	'
Discount rate, benefit obligations (as a percent)	'	4.00%	3.25%	'
Weighted average assumptions to determine the net periodic benefit cost	'	'	'	'
Discount rate, net periodic benefit (as a percent)	'	3.25%	4.25%	'

Pension_and_Other_PostRetireme4

Pension and Other Post-Retirement Benefit Plans (Details 3)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Domestic broadly diversified equity securities

Domestic broadly diversified equity securities

Domestic broadly diversified equity securities

Domestic broadly diversified equity securities

Fixed income securities

Fixed income securities

Fixed income securities

Fixed income securities

International broadly diversified equity securities

International broadly diversified equity securities

International broadly diversified equity securities

International broadly diversified equity securities

Alternative fixed income securities

Alternative fixed income securities

Alternative fixed income securities

Alternative fixed income securities

Cash and equivalent investments

Cash and equivalent investments

Cash and equivalent investments

Cash and equivalent investments

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Pension asset allocation and target allocation for 2014 by asset category

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Target allocation 2014 (as a percent)

'

'

'

'

40.00%

60.00%

'

'

20.00%

50.00%

'

'

5.00%

15.00%

'

'

0.00%

10.00%

'

'

0.00%

15.00%

Plan assets (as a percent)

100.00%

100.00%

42.00%

53.00%

'

'

29.00%

32.00%

'

'

7.00%

10.00%

'

'

4.00%

4.00%

'

'

18.00%

1.00%

'

'

Pension_and_Other_PostRetireme5

Pension and Other Post-Retirement Benefit Plans (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans costs	'	'	'
Expense recognized related to 401(k) employee savings plans	$14,600,000	$12,000,000	$10,100,000
Pension Benefits	'	'	'
Defined Benefit Plans costs	'	'	'
Cash contributions to pension plan	2,639,000	2,857,000	4,300,000
Expected cash payments related to its pensions	400,000	'	'
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 2014	2,500,000	'	'
Defined benefit plan, expected future benefit payments in year 2015	2,200,000	'	'
Defined benefit plan, expected future benefit payments in year 2016	2,000,000	'	'
Defined benefit plan, expected future benefit payments in year 2017	1,800,000	'	'
Defined benefit plan, expected future benefit payments in year 2018	1,900,000	'	'
Defined benefit plan, expected future benefit payments in the five years after 2018	8,400,000	'	'
Other Benefits	'	'	'
Defined Benefit Plans costs	'	'	'
Cash contributions to pension plan	328,000	146,000	'
Defined benefit plan, expected future benefit payments in year 2014	1,900,000	'	'
Defined benefit plan, expected future benefit payments in year 2015	1,800,000	'	'
Defined benefit plan, expected future benefit payments in year 2016	1,800,000	'	'
Defined benefit plan, expected future benefit payments in year 2017	1,700,000	'	'
Defined benefit plan, expected future benefit payments in year 2018	1,700,000	'	'
Defined benefit plan, expected future benefit payments in the five years after 2018	$7,700,000	'	'

Pension_and_Other_PostRetireme6

Pension and Other Post-Retirement Benefit Plans (Details 5) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Quoted prices in active markets for identical assets (Level 1) | Mutual Funds	'	'
Defined Benefit Plans costs	'	'
Fair value of plan assets	$6,900,000	$8,800,000
Significant other observable inputs (Level 2)	'	'
Defined Benefit Plans costs	'	'
Assets transferred from Level 1 to Level 2	'	9,800,000
Significant other observable inputs (Level 2) | Common Collective Trusts	'	'
Defined Benefit Plans costs	'	'
Fair value of plan assets	$13,200,000	$38,200,000

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in accumulated other comprehensive income (loss)	'	'	'
Balance at the beginning of the period	$99,547	'	'
Gains recognized in accumulated OCI, net of tax	12,750	'	'
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax	-67,594	'	'
Other comprehensive (loss) income	-54,844	-88,594	150,037
Balance at the end of the period	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	138,188	'	'
Gains recognized in accumulated OCI, net of tax	10,669	'	'
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax	-87,158	'	'
Other comprehensive (loss) income	-76,489	'	'
Balance at the end of the period	61,699	'	'
Cash flow hedge, net of tax | Interest rate	'	'	'
Changes in accumulated other comprehensive income (loss)	'	'	'
Balance at the beginning of the period	-1,276	'	'
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax	144	'	'
Other comprehensive (loss) income	144	'	'
Balance at the end of the period	-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	-37,365	'	'
Gains recognized in accumulated OCI, net of tax	2,081	'	'
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax	19,420	'	'
Other comprehensive (loss) income	21,501	'	'
Balance at the end of the period	($15,864)	'	'

Common_Stock_and_Earnings_Per_2

Common Stock and Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reserved, Authorized and Unissued Common Stock	'	'	'	'	'	'	'	'	'	'	'
Possible future acquisitions (in shares)	20,457	'	'	'	'	'	'	'	20,457	'	'
Stock compensation plans (in shares)	8,911	'	'	'	'	'	'	'	8,911	'	'
Total (in shares)	29,368	'	'	'	'	'	'	'	29,368	'	'
Basic earnings per common share:	'	'	'	'	'	'	'	'	'	'	'
Net income attributable to EQT Corporation	$115,205	$88,256	$86,856	$100,255	$48,041	$31,873	$31,446	$72,035	$390,572	$183,395	$479,769
Average common shares outstanding	'	'	'	'	'	'	'	'	150,574	149,619	149,392
Net income (in dollars per share)	$0.76	$0.59	$0.58	$0.67	$0.32	$0.21	$0.21	$0.48	$2.59	$1.23	$3.21
Diluted earnings per common share:	'	'	'	'	'	'	'	'	'	'	'
Net income attributable to EQT Corporation	$115,205	$88,256	$86,856	$100,255	$48,041	$31,873	$31,446	$72,035	$390,572	$183,395	$479,769
Average common shares outstanding	'	'	'	'	'	'	'	'	150,574	149,619	149,392
Potentially dilutive securities:	'	'	'	'	'	'	'	'	'	'	'
Stock options and awards (in shares)	'	'	'	'	'	'	'	'	1,213	887	817
Total (in shares)	'	'	'	'	'	'	'	'	151,787	150,506	150,209
Net income (in dollars per share)	$0.75	$0.58	$0.57	$0.66	$0.32	$0.21	$0.21	$0.48	$2.57	$1.22	$3.19
Options to purchase common stock excluded from potentially dilutive securities (in shares)	'	'	'	'	'	'	'	'	0	281,528	6,480

ShareBased_Compensation_Plans_1

Share-Based Compensation Plans (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Jan. 02, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Jan. 02, 2013

Feb. 29, 2012

Dec. 31, 2013

Dec. 31, 2012

Jan. 31, 2013

Jan. 02, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Discontinued operations

Discontinued operations

Discontinued operations

2008 Executive Performance Incentive Program

2010 Executive Performance Incentive Plan

2010 Executive Performance Incentive Plan

2010 Executive Performance Incentive Plan

2012 Executive Performance Incentive Plan

2012 Executive Performance Incentive Plan

2012 Executive Performance Incentive Plan

2012 Executive Performance Incentive Plan

2012 Executive Performance Incentive Plan

2013 Executive Performance Incentive Plan

2013 Executive Performance Incentive Plan

2013 Executive Performance Incentive Plan

2007 Supply Long-Term Incentive Program

2010 Stock Incentive Award program

2010 Stock Incentive Award program

2011 EQT Value Driver Award Program

2011 EQT Value Driver Award Program

2011 EQT Value Driver Award Program

2011 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2013 EQT Value Driver Award Program

2011 Volume and Efficiency Program

2011 Volume and Efficiency Program

2011 Volume and Efficiency Program

Restricted Stock Awards

Restricted Stock Awards

Restricted Stock Awards

Restricted Stock Awards

Non-Qualified Stock Options

Non-Qualified Stock Options

Non-Qualified Stock Options

Non-employee Directors' Share-Based Awards

Non-employee Directors' Share-Based Awards

Non-employee Directors' Share-Based Awards

EQM Total Return Program

EQM Total Return Program

EQM non-employee directors' share-based awards

EQM non-employee directors' share-based awards

Minimum

Maximum

Minimum

Maximum

item

Discontinued operations

Share-Based Compensation Plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based compensation expense

$58,544,000

$45,821,000

$40,329,000

$741,000

$670,000

$352,000

$923,000

$1,940,000

$2,118,000

'

$6,739,000

$10,633,000

'

'

'

$6,602,000

'

'

$198,000

$4,022,000

$4,241,000

$3,033,000

$15,807,000

'

'

$2,327,000

$11,557,000

'

'

$13,050,000

$13,834,000

$5,286,000

$5,384,000

$3,033,000

$2,007,000

$1,929,000

'

$3,805,000

$3,580,000

$6,057,000

$7,432,000

$2,558,000

$3,320,000

$837,000

$419,000

$144,000

$116,000

Cash received from exercises of all share-based payment arrangements for employees and directors

32,900,000

7,900,000

3,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income tax benefit by the exercise of nonqualified employee stock options and vesting of restricted share awards

14,400,000

15,100,000

8,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Excess tax benefit

'

8,100,000

6,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Units distributed, number

'

'

'

'

'

'

44,400

115,590

'

'

'

'

'

'

'

'

'

'

'

294,925

'

'

'

'

'

'

'

'

'

'

'

'

'

91,478

'

'

23,053

'

'

'

'

'

'

'

'

'

'

Compensation plan, award as a percentage of target award level

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

0.00%

300.00%

'

0.00%

300.00%

'

'

'

'

'

'

'

'

'

'

'

'

300.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of tranches

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Value of vested stock-based awards distributed in cash and stock

'

'

'

'

'

'

2,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15,300,000

'

'

14,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Value of vested stock-based awards distributed in cash and stock

'

'

'

'

'

'

'

6,900,000

'

'

'

'

'

'

'

'

'

'

'

12,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

4,287,701

1,600,000

5,100,000

1,300,000

'

'

'

'

'

'

'

'

'

'

Period after which the shares granted will be fully vested

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'3 years

'3 years

'

'

'

'

'

'

'

'

'

'

'

Share units outstanding

'

'

'

'

'

'

'

'

'

'

335,055

'

'

'

'

297,597

'

'

'

'

'

'

'

228,640

'

196,609

'

204,679

409,357

614,048

221,140

'

'

182,378

204,118

'

'

'

'

'

'

'

'

'

'

'

'

Share units outstanding

'

'

'

'

'

'

'

'

'

'

'

'

351,480

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

179,639

'

'

'

'

'

'

Weighted Average Fair Value of shares, Granted (in dollars per share)

'

'

'

'

'

'

'

'

'

$60.09

$123.37

'

'

'

'

$126.45

'

'

'

'

'

'

'

'

'

'

$54.79

'

'

$58.98

$48.06

'

'

$70.59

$54

$52

'

'

'

'

'

'

'

'

'

'

'

Non-employee Directors' weighted average fair value of shares, Granted (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$58.98

$53.47

$44.84

'

'

'

'

Expected term

'

'

'

'

'

'

'

'

'

'3 years

'

'3 years

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'5 years

'5 years

'

'

'

'

'

'

'

Risk-free interest rate (as a percent)

'

'

'

'

'

'

'

'

'

1.69%

'

0.36%

'

'

'

0.36%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.76%

0.89%

2.02%

'

'

'

'

'

'

'

Capitalized compensation cost

'

'

'

'

'

'

'

'

'

'

$8,100,000

$2,100,000

'

'

'

$5,000,000

'

'

'

'

'

'

'

'

'

$2,600,000

$5,000,000

'

'

$14,100,000

$2,800,000

$2,500,000

$1,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Award vested at end of year one, percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

50.00%

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Award vested at end of year two, percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

50.00%

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

ShareBased_Compensation_Plans_2

Share-Based Compensation Plans (Details 2) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Jan. 02, 2013

Dec. 31, 2012

Jan. 02, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Jan. 31, 2013

Jan. 02, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jul. 02, 2012

Jul. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

2012 Executive Performance Incentive Plan

2012 Executive Performance Incentive Plan

2012 Executive Performance Incentive Plan

2010 Stock Incentive Award program

2011 EQT Value Driver Award Program

2011 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2012 EQT Value Driver Award Program

2011 Volume and Efficiency Program

Restricted Stock Awards

Restricted Stock Awards

Restricted Stock Awards

Restricted Stock Awards

Non-employee Directors' Share-Based Awards

Non-employee Directors' Share-Based Awards

Non-employee Directors' Share-Based Awards

Performance awards

Performance awards

Performance awards

Phantom units

Phantom units

2013 EQT Value Driver Award Program

2013 Executive Performance Incentive Plan

Non-Qualified Stock Options

Non-Qualified Stock Options

Non-Qualified Stock Options

2014 Value Driver Award Programs

2014 Stock Options

2014 Executive Performance Incentive Program

2014 EQM Value Driver program

Minimum

Minimum

Minimum

Minimum

Minimum

Minimum

Maximum

Maximum

Maximum

Maximum

Maximum

Maximum

Discontinued operations

2012 Executive Performance Incentive Plan

Performance awards

2013 Executive Performance Incentive Plan

2014 Value Driver Award Programs

2014 Executive Performance Incentive Program

2014 EQM Value Driver program

2012 Executive Performance Incentive Plan

Performance awards

2013 Executive Performance Incentive Plan

2014 Value Driver Award Programs

2014 Executive Performance Incentive Program

2014 EQM Value Driver program

Share-Based Compensation Plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period after which the shares granted will be fully vested

'

'

'

'

'

'

'

'

'

'

'

'3 years

'3 years

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation costs on non-vested awards

$13,800,000

'

'

'

'

'

'

'

'

'

'

$7,000,000

'

'

'

'

'

'

'

'

$1,700,000

'

'

$9,000,000

$23,200,000

$2,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-employee Directors' share-based awards outstanding

'

'

351,480

'

'

'

'

'

'

'

'

'

'

'

'

179,639

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-employee Directors' share-based awards granted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,500

28,140

22,140

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-employee Directors' weighted average fair value of shares, Granted (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$58.98

$53.47

$44.84

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-Vested Shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares Outstanding, Beginning of Period

'

'

'

'

228,640

'

'

196,609

204,679

409,357

'

204,118

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of shares granted

'

351,480

'

'

'

'

'

'

'

'

'

101,510

103,730

65,390

'

'

'

'

146,490

146,490

142,500

3,790

4,780

'

314,280

'

'

'

187,160

'

278,430

32,840

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of unitholder return realized on common units from the date of grant

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

Non-vested shares, Vested

'

'

'

-294,925

'

'

'

'

'

'

'

-91,478

'

'

-23,053

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-vested shares, Forfeited

-16,425

'

'

'

'

'

'

'

'

'

-7,500

-31,772

'

'

-18,357

'

'

'

'

'

-3,990

'

'

'

-16,683

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares Outstanding, End of Period

335,055

'

'

'

228,640

'

'

196,609

204,679

409,357

221,140

182,378

204,118

'

'

'

'

'

'

'

146,490

8,886

'

614,048

297,597

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Fair Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Fair Value, Beginning of Period (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

$49.86

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Fair Value of shares, Granted (in dollars per share)

$123.37

'

'

'

'

'

$54.79

'

'

'

$48.06

$70.59

$54

$52

'

'

'

'

'

'

$20.02

$37.92

$24.30

$58.98

$126.45

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Fair Value of shares, Vested (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

$46.87

'

'

$56.28

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Fair Value of shares, Forfeited (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

$55.15

'

'

$55

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Fair Value, End of Period (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

$61.98

$49.86

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted Stock, Aggregate Fair Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Fair Value, Beginning of Period

'

'

'

'

'

'

'

'

'

'

'

10,176,930

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Fair Value of shares, Granted

'

'

'

'

'

'

'

'

'

'

'

7,166,006

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Fair Value of shares, Vested

'

'

'

-12,600,000

'

'

'

'

'

'

'

-4,287,701

-1,600,000

-5,100,000

-1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Fair Value of shares, Forfeited

'

'

'

'

'

'

'

'

'

'

'

-1,752,243

'

'

-1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Fair Value, End of Period

'

'

'

'

'

'

'

'

'

'

'

11,302,992

10,176,930

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Assumptions used in the Black-Scholes single option pricing model

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Risk-free interest rate (as a percent)

'

0.36%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.36%

0.76%

0.89%

2.02%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividend yield (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.22%

1.64%

2.19%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Volatility factor (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

38.00%

'

'

'

'

31.69%

31.44%

28.92%

'

'

'

'

'

27.00%

'

'

'

'

'

72.00%

'

'

'

'

Expected term

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'5 years

'5 years

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Grants in period (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

259,600

278,300

229,100

'

133,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-Qualified Stock Options, weighted average grant date fair value (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$16.72

$13.19

$10.06

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-Qualified Stock Options, total intrinsic value of options exercised

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22,800,000

11,800,000

18,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options, Shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options Outstanding, Beginning of Period (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,864,375

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options, Granted (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

259,600

278,300

229,100

'

133,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options, Exercised (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-8,100

'

'

'

'

'

'

'

'

'

'

-637,174

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options, Forfeited (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-4,800

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options Outstanding, End of Period (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,482,001

1,864,375

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options Exercisable, End of Period (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,088,051

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options, Weighted Average Exercise Price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Exercise Price, Beginning of Period (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$46.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Exercise Price of shares, Granted (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$58.98

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Exercise Price of shares, Exercised (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$24.39

'

'

'

'

'

'

'

'

'

'

$42.44

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Exercise Price of shares, Forfeited (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$58.98

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Exercise Price, End of Period (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$49.77

$46.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Exercise Price of shares, Exercisable (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$46.98

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-Qualified Stock Options, Weighted Average Remaining Contractual Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Remaining Contractual Term, End of Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'4 years 8 months 12 days

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Remaining Contractual Term, Exercisable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years 3 months 18 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-qualified Stock Options, Aggregate Intrinsic Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Intrinsic Value Outstanding, End of Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

59,287,589

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Intrinsic Value Exercisable, End of Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$46,570,891

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation costs on non-vested awards, weighted average period of recognition

'

'

'

'

'

'

'

'

'

'

'

'1 year 8 months 12 days

'

'

'

'

'

'

'

'

'2 years

'

'

'

'2 years

'

'

'

'

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'

'

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'

'

'

'

'

'

'

'

'

'

Award vested at end of year one, percentage

'

'

'

'

'

50.00%

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

50.00%

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

Award vested at end of year two, percentage

'

'

'

'

'

50.00%

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

50.00%

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

Compensation plan, award as a percentage of target award level

'

'

'

'

'

'

'

'

'

'

300.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.00%

'

0.00%

0.00%

0.00%

0.00%

300.00%

'

300.00%

300.00%

300.00%

300.00%

2013 Stock Options

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

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'

Term of stock options

'

'

'

'

'

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'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'4 years 8 months 12 days

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercise price of stock options (in dollars per share)

'

'

'

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'

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'

'

'

'

'

'

'

'

'

'

'

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'

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$89.78

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'

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'

'

'

Concentrations_of_Credit_Risk_

Concentrations of Credit Risk (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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 (as a percent)	82.00%	82.00%	'
EQT Production | Minimum | Sales revenue goods, net	'	'	'
Concentration Risk	'	'	'
Percentage required for qualification as major customer	10.00%	10.00%	10.00%
EQT Production | Customer concentration | Sales revenue goods, net	'	'	'
Concentration Risk	'	'	'
Number of customers	1	'	'
Concentration risk (as a percent)	11.00%	'	'

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines	'
Remedial action included in other credits	$0.60
Pipeline demand charges	'
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines	'
Amount due as of the balance sheet date	2,167.80
Amount due in 2014	140.8
Amount due in 2015	192.4
Amount due in 2016	184.8
Amount due in 2017	180.8
Amount due in 2018	180.8
Thereafter	1,288.20
Drilling equipment and services supply agreements	'
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines	'
Amount due as of the balance sheet date	$70.40

Commitments_and_Contingencies_1

Commitments and Contingencies (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating leases, future minimum payments due:	'	'	'
Total as of balance sheet date	$134.20	'	'
Due 2014	42.9	'	'
Due 2015	25.6	'	'
Due 2016	18.4	'	'
Due 2017	10.7	'	'
Due 2018	6.3	'	'
Due after 2018	30.3	'	'
Operating lease rentals for drilling contractors, office locations, warehouse buildings and some equipment	$56	$45	$74.70

Guarantees_Details

Guarantees (Details) (USD $)	12 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2008	Dec. 31, 2013	Dec. 31, 2013
	NORESCO Guarantees, Total	NORESCO Guarantees, Total	NORESCO Guarantees, Energy Savings
Undiscounted maximum aggregate payments related to guarantees	'	'	$172
Guarantee obligations term	'	'	'P14Y
NORESCO purchaser's obligation for loss reimbursement to the company, maximum exposure	'	6	'
Third party letter of credit amount supporting the NORESCO purchaser's guarantee obligations	$1	'	'

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, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interim Financial Information (Unaudited)	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	$493,429	$479,606	$473,093	$415,883	$406,273	$337,916	$298,742	$334,291	$1,862,011	$1,377,222	$1,323,829
Operating income	181,081	167,064	161,980	144,479	126,505	81,253	70,817	111,054	654,604	389,629	761,171
Income from continuing operations	61,933	86,199	81,466	69,131	33,123	29,010	25,302	48,467	298,729	135,902	419,582
Income from discontinued operations	53,272	2,057	5,390	31,124	14,918	2,863	6,144	23,568	91,843	47,493	60,187
Net income attributable to EQT Corporation	$115,205	$88,256	$86,856	$100,255	$48,041	$31,873	$31,446	$72,035	$390,572	$183,395	$479,769
Basic:	'	'	'	'	'	'	'	'	'	'	'
Income from continuing operations (in dollars per share)	$0.41	$0.57	$0.54	$0.46	$0.22	$0.19	$0.17	$0.32	$1.98	$0.91	$2.81
Income from discontinued operations (in dollars per share)	$0.35	$0.02	$0.04	$0.21	$0.10	$0.02	$0.04	$0.16	$0.61	$0.32	$0.40
Net income (in dollars per share)	$0.76	$0.59	$0.58	$0.67	$0.32	$0.21	$0.21	$0.48	$2.59	$1.23	$3.21
Diluted:	'	'	'	'	'	'	'	'	'	'	'
Income from continuing operations (in dollars per share)	$0.40	$0.57	$0.54	$0.46	$0.22	$0.19	$0.17	$0.32	$1.97	$0.90	$2.79
Income from discontinued operations (in dollars per share)	$0.35	$0.01	$0.03	$0.20	$0.10	$0.02	$0.04	$0.16	$0.60	$0.32	$0.40
Net income (in dollars per share)	$0.75	$0.58	$0.57	$0.66	$0.32	$0.21	$0.21	$0.48	$2.57	$1.22	$3.19

Natural_Gas_Producing_Activiti2

Natural Gas Producing Activities (Unaudited) (Details) (USD $)	12 Months Ended			0 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 03, 2013	Jun. 03, 2013	Dec. 31, 2013
				Chesapeake	Chesapeake	Chesapeake
					Marcellus	Marcellus
Capitalized costs oil and gas producing activities net	'	'	'	'	'	'
Capitalized costs	$8,152,951,000	$6,750,343,000	$5,772,083,000	'	'	'
Accumulated depreciation and depletion	2,134,953,000	1,572,775,000	1,177,526,000	'	'	'
Net capitalized costs	6,017,998,000	5,177,568,000	4,594,557,000	'	'	'
Property acquisition:	'	'	'	'	'	'
Proved properties	90,390,000	16,965,000	108,717,000	'	57,000,000	57,000,000
Unproved properties	95,861,000	117,654,000	41,085,000	57,200,000	'	'
Exploration	4,285,000	4,827,000	2,344,000	'	'	'
Development	1,230,301,000	850,854,000	928,294,000	'	'	'
Costs incurred	'	'	'	'	'	'
Purchase price of acquisition allocated to acquired wells	90,390,000	16,965,000	108,717,000	'	57,000,000	57,000,000
Liabilities assumed in exchange for proved developed properties	'	'	92,600,000	'	'	'
Revenues:	'	'	'	'	'	'
Affiliated	5,912,000	3,433,000	6,225,000	'	'	'
Nonaffiliated	1,162,745,000	790,340,000	785,060,000	'	'	'
Production costs	108,091,000	96,155,000	80,911,000	'	'	'
Exploration costs	18,483,000	10,370,000	4,932,000	'	'	'
Depreciation, depletion and accretion	578,641,000	409,628,000	257,144,000	'	'	'
Income tax expense	183,060,000	109,660,000	174,835,000	'	'	'
Results of operations from producing activities (excluding corporate overhead)	$280,382,000	$167,960,000	$273,463,000	'	'	'

Natural_Gas_Producing_Activiti3

Natural Gas Producing Activities (Unaudited) (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item	Mcfe	Mcfe
	Mcfe	item
Natural Gas Producing Activities (Unaudited)	'	'	'
Experience of primary Company engineer	'25 years	'	'
Independent audit review percentage of total gas and hydrocarbon reserves	100.00%	'	'
Percentage of proved reserves covered by a detail, well by well, independent audit	80.00%	'	'
Percentage of properties covered by an independent audit of aggregated groups of wells	20.00%	'	'
Maximum number of wells per group in the independent audit of aggregated groups	200	'	'
Number of fields of the company with a decrease in lateral spacing	1	1	'
Proved developed reserves:	'	'	'
Acquisition of proved developed reserves (Bcfe)	39,700,000	'	'
Actual production (in Bcfe)	367,100,000	261,000,000	198,800,000
Increase in reserves due to extensions, discoveries and other additions (in Bcfe)	2,046,600,000	1,655,800,000	694,200,000
Upward or (downward) revision in previous natural gas equivalent reserve estimates (in Bcfe)	191,500,000	-754,200,000	-388,400,000
Upward revision in previous natural gas equivalent reserve estimates which was partially offset by negative revisions (in Bcfe)	-349,000,000	'	'
Number of undeveloped locations and associated reserves that were removed	58	'	'
Price per barrel used in computation of reserves (in dollars per Bbl)	89.22	82.9	92.84
Maximum period for which reserves are classified as proved undeveloped	'5 years	'	'
Columbia Gas Transmission Corp	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of reserves (in dollars per Dth)	3.653	2.793	4.198
Dominion Transmission, Inc	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of reserves (in dollars per Dth)	3.447	2.785	4.243
East Tennessee Natural Gas Pipeline	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of reserves (in dollars per Dth)	3.693	2.769	4.159
Transcontinental Gas Pipe Line Corp	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of reserves (in dollars per Dth)	3.521	2.878	4.172
Marcellus	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of additional reserves (in dollars per Dth)	'	0.591	1.139
Kentucky	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of additional reserves (in dollars per Dth)	'	0.764	2.149
Wetzel County	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of additional reserves (in dollars per Dth)	'	0.398	'
Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of reserves (in dollars per Dth)	2.842	2.403	'
Texas Eastern Transmission Corp	'	'	'
Distribution Channel	'	'	'
Prices used in calculation of reserves (in dollars per Dth)	3.495	2.782	'
Natural Gas	'	'	'
Proved developed and undeveloped reserves:	'	'	'
Beginning of year	5,985,758	5,347,386	5,205,692
Revision of previous estimates	-375,887	-755,788	-393,129
Purchase of natural in place	472,798	'	39,436
Sale of natural in place	-455	-694	-1,223
Extensions, discoveries and other additions	1,844,840	1,654,228	694,180
Production	-365,493	-259,374	-197,570
End of year	7,561,561	5,985,758	5,347,386
Proved developed reserves:	'	'	'
Beginning of year, proved developed reserves	2,779,187	2,948,546	2,520,569
End of year, proved developed reserves	3,567,313	2,779,187	2,948,546
Oil	'	'	'
Proved developed and undeveloped reserves:	'	'	'
Beginning of year	3,199	2,931	2,307
Revision of previous estimates	270	265	781
Purchase of natural in place	'	'	51
Extensions, discoveries and other additions	757	268	'
Production	-270	-265	-208
End of year	3,956	3,199	2,931
Proved developed reserves:	'	'	'
Beginning of year, proved developed reserves	3,199	2,931	2,307
End of year, proved developed reserves	3,892	3,199	2,931
Equivalent number of million cubic feet of natural gas in each thousand barrels of oil	6	'	'
Production barrels of oil equivalents	1,000	'	'
NGLs	'	'	'
Proved developed and undeveloped reserves:	'	'	'
Revision of previous estimates	94,296	'	'
Extensions, discoveries and other additions	32,866	'	'
End of year	127,162	'	'
Proved developed reserves:	'	'	'
End of year, proved developed reserves	65,837	'	'
Equivalent number of million cubic feet of natural gas in each thousand barrels of oil	6	'	'
Production barrels of oil equivalents	1,000	'	'

Natural_Gas_Producing_Activiti4

Natural Gas Producing Activities (Unaudited) (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Natural Gas Producing Activities (Unaudited)	'	'	'
Discount rate percentage	10.00%	'	'
Future cash inflows	$25,912,542,000	$15,250,019,000	$22,145,953,000
Future production costs	-4,180,136,000	-3,070,957,000	-3,435,200,000
Future development costs	-4,199,722,000	-3,082,053,000	-2,600,982,000
Future income tax expenses	-6,533,817,000	-3,324,472,000	-6,075,539,000
Future net cash flow	10,998,867,000	5,772,537,000	10,034,232,000
10% annual discount for estimated timing of cash flows	-7,047,588,000	-3,617,378,000	-6,101,408,000
Standardized measure of discounted future net cash flows	3,951,279,000	2,155,159,000	3,932,824,000
Change in price of natural gas used in sensitivity analysis (in dollars per Dth)	1	'	'
Change in price of oil used in sensitivity analysis (in dollars per Bbl)	10	'	'
Change in discounted future cash flows for natural gas if assume $1 per Dth price change	3,200,000,000	'	'
Change in discounted future cash flows for oil if assume $10 per barrel price change	15,600,000	'	'
Schedule of changes in the standardized measure of discounted future net cash flows	'	'	'
Sales and transfers of natural gas and oil produced - net	-1,060,566,000	-697,618,000	-710,373,000
Net changes in prices, production and development costs	-292,533,000	-3,530,086,000	52,057,000
Extensions, discoveries and improved recovery, less related costs	1,509,002,000	917,986,000	806,597,000
Development costs incurred	1,319,135,000	548,852,000	498,175,000
Purchase of minerals in place - net	348,608,000	'	46,178,000
Sale of minerals in place - net	-252,000	-807,000	-1,124,000
Revisions of previous quantity estimates	106,170,000	-876,336,000	-356,830,000
Accretion of discount	343,502,000	622,072,000	478,165,000
Net change in income taxes	-1,031,105,000	1,127,272,000	-560,360,000
Timing and other	554,159,000	111,000,000	622,127,000
Net increase (decrease)	1,796,120,000	-1,777,665,000	874,612,000
Beginning of year	2,155,159,000	3,932,824,000	3,058,212,000
End of year	$3,951,279,000	$2,155,159,000	$3,932,824,000

Natural_Gas_Producing_Activiti5

Natural Gas Producing Activities (Unaudited) (Details 4) (Appalachian Natural Gas Trust)	Apr. 30, 2011
Appalachian Natural Gas Trust	'
Equity in Nonconsolidated Investments	'
Ownership percentage	1.00%

SCHEDULE_II_VALUATION_AND_QUAL1

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) (Allowance for doubtful accounts, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Allowance for doubtful accounts	'	'	'
Movement in Valuation Allowances and Reserves	'	'	'
Balance at Beginning of Period	$5,883	$7,626	$7,324
Additions Charged to Costs and Expenses (Income)	-704	-1,637	327
Deductions	8	106	25
Balance at End of Period	$5,171	$5,883	$7,626