Gastar Exploration (GST) 10-K 12 Mar 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Mar. 11, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	Gastar Exploration Inc.
Entity Central Index Key	1431372
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$507.90
Entity Common Stock, Shares Outstanding		80,195,695

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$11,008	$32,393
Accounts receivable, net of allowance for doubtful accounts of $0 and $507, respectively	30,841	21,656
Commodity derivative contracts	19,687	0
Prepaid expenses	2,083	1,145
Total current assets	63,619	55,194
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	128,274	96,220
Proved properties	1,124,367	935,773
Total oil and natural gas properties	1,252,641	1,031,993
Furniture and equipment	3,010	2,691
Total property, plant and equipment	1,255,651	1,034,684
Accumulated depreciation, depletion and amortization	-563,351	-517,171
Total property, plant and equipment, net	692,300	517,513
OTHER ASSETS:
Commodity derivative contracts	7,815	7,545
Deferred charges, net	2,586	2,950
Advances to operators and other assets	9,474	6,733
Total other assets	19,875	17,228
TOTAL ASSETS	775,794	589,935
CURRENT LIABILITIES:
Accounts payable	28,843	11,046
Revenue payable	9,122	12,514
Accrued interest	3,528	3,504
Accrued drilling and operating costs	5,977	8,756
Advances from non-operators	1,820	9,259
Commodity derivative contracts	0	3,403
Commodity derivative premium payable	2,481	145
Asset retirement obligation	82	633
Other accrued liabilities	3,175	4,844
Total current liabilities	55,028	54,104
LONG-TERM LIABILITIES:
Long-term debt	360,303	312,994
Commodity derivative contracts	0	378
Commodity derivative premium payable	4,702	7,000
Asset retirement obligation	5,475	5,430
Total long-term liabilities	370,480	325,802
Commitments and contingencies (Note 14)
STOCKHOLDERS' EQUITY:
Common stock	78	61
Additional paid-in capital	568,440	464,730
Accumulated deficit	-218,294	-254,823
Total stockholders' equity	350,286	210,029
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	775,794	589,935
Series A Preferred Stock
STOCKHOLDERS' EQUITY:
Preferred stock	41	40
Series B Preferred Stock
STOCKHOLDERS' EQUITY:
Preferred stock	$21	$21

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Accounts receivable, doubtful accounts	$0	$507
Common stock, par value	$0.00	$0.00
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	78,632,810	61,211,658
Common stock, shares outstanding	78,632,810	61,211,658
Series A Preferred Stock
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	4,045,000	3,958,160
Preferred stock, shares outstanding	4,045,000	3,958,160
Preferred Stock, liquidation preference per share	$25	$25
Series B Preferred Stock
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	2,140,000	2,140,000
Preferred stock, shares outstanding	2,140,000	2,140,000
Preferred Stock, liquidation preference per share	$25	$25

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES:
Oil and condensate	$82,820	$36,480	$11,570
Natural gas	47,647	40,416	23,318
NGLs	21,382	15,611	7,630
Total oil and condensate, natural gas and NGLs revenues	151,849	92,507	42,518
Gain (loss) on commodity derivatives contracts	19,569	-4,752	7,422
Total revenues	171,418	87,755	49,940
EXPENSES:
Production taxes	6,733	4,651	2,269
Lease operating expenses	19,323	9,456	6,174
Transportation, treating and gathering	3,679	4,006	4,965
Depreciation, depletion and amortization	46,180	32,449	25,424
Impairment of natural gas and oil properties	0	0	150,787
Accretion of asset retirement obligation	506	468	388
General and administrative expense	16,485	16,961	12,211
Litigation settlement expense	0	1,000	1,250
Total expenses	92,906	68,991	203,468
INCOME (LOSS) FROM OPERATIONS	78,512	18,764	-153,528
OTHER INCOME (EXPENSE):
Gain on acquisition of assets at fair value, net of income taxes	0	27,670	0
Interest expense	-27,571	-13,168	-270
Investment and other income	19	48	9
Foreign transaction loss	-7	-14	-2
INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES	50,953	33,300	-153,791
Income tax benefit	0	-16,042	0
NET INCOME (LOSS)	50,953	49,342	-153,791
Dividends on preferred stock	-14,424	-9,378	-7,077
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$36,529	$39,964	($160,868)
NET INCOME (LOSS) PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic (in dollars per share)	$0.58	$0.66	($2.53)
Diluted (in dollars per share)	$0.55	$0.63	($2.53)
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic (shares)	63,270,733	60,220,115	63,538,362
Diluted (shares)	66,492,589	63,618,401	63,538,362

Consolidated_Statement_of_Stoc

Consolidated Statement of Stockholders' Equity (USD $)	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Series A Preferred Stock	Series B Preferred Stock
In Thousands, except Share data, unless otherwise specified					Preferred Stock	Preferred Stock
Balance at beginning of period at Dec. 31, 2011	$235,194	$316,346	$52,753	($133,919)	$14	$0
Balance at beginning of period (in shares) at Dec. 31, 2011		64,706,750			1,364,543	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of preferred stock (shares)					2,586,711
Issuance of preferred stock	49,250		49,224		26
Issuance of restricted stock (shares)		1,916,980
Issuance of restricted stock	0
Forfeitures of restricted stock (shares)		-191,728
Forfeitures of restricted stock	-335		-335
Exercise of stock options, net of forfeitures (shares)		607
Stock based compensation	3,295		3,295
Preferred stock dividends	-7,077			-7,077
Net income (loss)	-153,791			-153,791
Balance at end of period at Dec. 31, 2012	126,536	316,346	104,937	-294,787	40	0
Balance at end of period (in shares) at Dec. 31, 2012		66,432,609			3,951,254	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of preferred stock (shares)					6,906	2,140,000
Issuance of preferred stock	50,181		50,160			21
Repurchase of common stock (shares)		-6,781,768
Repurchase of shares of common stock	-9,753	-9,753
Reclassification of par value of common stock		-306,532	306,532
Issuance of restricted stock (shares)		2,288,179
Issuance of restricted stock	0
Forfeitures of restricted stock (shares)		-737,362
Forfeitures of restricted stock	-334		-334
Exercise of stock options, net of forfeitures (shares)	10,000	10,000
Stock based compensation	3,435		3,435
Preferred stock dividends	-9,378			-9,378
Net income (loss)	49,342			49,342
Balance at end of period at Dec. 31, 2013	210,029	61	464,730	-254,823	40	21
Balance at end of period (in shares) at Dec. 31, 2013		61,211,658			3,958,160	2,140,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of preferred stock (shares)					86,840
Issuance of preferred stock	2,066		2,065		1
Issuance of preferred stock (shares)		17,000,000
Issuance of preferred stock	101,319	17	101,302
Exercise of stock options, net of forfeitures (shares)		472,189
Issuance of restricted stock (shares)		601,473
Issuance of restricted stock	0
Forfeitures of restricted stock (shares)		-659,227
Forfeitures of restricted stock	-4,562		-4,562
Exercise of stock options, net of forfeitures (shares)	7,500	6,717
Exercise of stock options, net of forfeitures	15		15
Stock based compensation	4,890		4,890
Preferred stock dividends	-14,424			-14,424
Net income (loss)	50,953			50,953
Balance at end of period at Dec. 31, 2014	$350,286	$78	$568,440	($218,294)	$41	$21
Balance at end of period (in shares) at Dec. 31, 2014		78,632,810			4,045,000	2,140,000

Consolidated_Statement_of_Stoc1

Consolidated Statement of Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Issuance of shares- cash, offering costs	$4,931

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$50,953		$49,342		($153,791)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	46,180		32,449		25,424
Impairment of natural gas and oil properties	0		0		150,787
Stock-based compensation	4,890		3,435		3,295
Total (gain) loss on commodity derivatives contracts	-19,569		4,752		-7,422
Cash settlements of matured commodity derivative contracts, net	-4,901		5,892		16,251
Cash premiums paid for commodity derivatives contracts	-185		-152		-4,539
Amortization of deferred financing costs	3,067	[1],[2]	2,322	[1],[2]	224	[1],[2]
Accretion of asset retirement obligation	506		468		388
Settlement of asset retirement obligation	-588		-66		-636
Gain on acquisition of assets at fair value	0		-27,670		0
Deferred tax benefit	0		-16,042		0
Changes in operating assets and liabilities:
Accounts receivable	-12,524		-8,431		2,487
Prepaid expenses	-938		-48		146
Accounts payable and accrued liabilities	-2,566		1,563		4,441
Net cash provided by operating activities	64,325		47,814		37,055
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties	-155,631		-95,343		-136,311
Advances to operators	-61,067		-22,213		-9,649
Acquisition of oil and natural gas properties - refund (expenditure)	4,209		-251,096		0
Proceeds from sale of oil and natural gas properties	5,530		112,201		0
Use of proceeds from non-operators	-7,439		-8,281		-1,983
Purchase of furniture and equipment	-319		-766		-296
Net cash used in investing activities	-214,717		-265,498		-148,239
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common shares, net of issuance costs	101,319		0		0
Repurchase of common stock	0		-9,753		0
Proceeds from revolving credit facility	103,000		19,000		98,000
Repayment of revolving credit facility	-58,000		-117,000		-30,000
Proceeds from issuance of senior secured notes, net of discount	0		312,279		0
Proceeds from issuance of preferred stock, net of issuance costs	2,064		50,183		49,250
Dividends on preferred stock	-14,424		-9,378		-7,077
Deferred financing charges	-405		-3,785		-450
Tax withholding related to restricted stock and PBU vestings	-4,562		-334		-336
Other	15		-36		51
Net cash provided by financing activities	129,007		241,176		109,438
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	-21,385		23,492		-1,746
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	32,393		8,901		10,647
CASH AND CASH EQUIVALENTS, END OF PERIOD	$11,008		$32,393		$8,901
[1]	The years ended DecemberB 31, 2014 and 2013 include $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes.
[2]	The year ended DecemberB 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. bLong-Term Debt - Second Amended and Restated Revolving Credit Facility.b

Description_Of_Business

Description Of Business	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of business	Description of Business
	Gastar Exploration Inc. (“Gastar”) is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Gastar’s principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, Gastar is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and expects to test other prospective formations on the same acreage, including the Woodford Shale and the Meramec Shale (middle Mississippi Lime), which Gastar refers to as the Stack Play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus Shale and has drilled its first successful dry gas Utica Shale/Point Pleasant well on its acreage. Gastar completed the sale of substantially all of its East Texas assets on October 2, 2013, with an effective date of January 1, 2013.
	On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation, changed its jurisdiction of incorporation to the State of Delaware and changed its name to “Gastar Exploration, Inc.” At December 31, 2013, Gastar Exploration, Inc. was a holding company and substantially all of its operations were conducted through, and substantially all of its assets were held by, its primary operating subsidiary, Gastar Exploration USA, Inc. and its wholly-owned subsidiaries. Subsequently, on January 31, 2014, Gastar Exploration, Inc. merged with and into Gastar Exploration USA, Inc. as part of a reorganization to eliminate the holding company corporate structure. Pursuant to the merger agreement, shares of Gastar Exploration, Inc.'s common stock were converted into an equal number of shares of common stock of Gastar Exploration USA, Inc. and Gastar Exploration USA, Inc. changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc., together with its subsidiary, owns and continues to conduct business in substantially the same manner as was being conducted by Gastar Exploration, Inc. and its subsidiaries prior to the merger. All references to “Gastar,” the “Company” and similar terms refer collectively to Gastar Exploration Inc. Unless otherwise stated or the context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) and its wholly-owned subsidiaries, all references to “Parent” refer solely to Gastar Exploration, Inc. (formerly known as Gastar Exploration Ltd.).

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies
	Basis of Presentation
	The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with U.S. GAAP. The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 18. “Supplemental Oil and Gas Disclosures.”
	All prior year balances are those of Gastar Exploration, Inc.
	Reclassifications
	Certain reclassifications of prior year balances have been made to conform to current year presentation; these reclassifications have no impact on net income (loss).
	Subsequent Events
	In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate.
	Principles of Consolidation
	The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation.
	Use of estimates in Preparation of Financial Statements
	The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties.
	Cash and Cash Equivalents
	The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $11.0 million and $32.4 million as of December 31, 2014 and 2013, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.
	Accounts Receivable
	Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible. A summary of the activity related to the allowance for doubtful accounts is as follows:
		For the years ended December 31,
		2014			2013			2012
		(in thousands)
	Allowance for doubtful accounts, beginning of year	$	507		$	546		$	551
	Expense	—			—			—
	Reductions/write-offs	(507		)	(39		)	(5		)
	Allowance for doubtful accounts, end of year	$	—		$	507		$	546
	Oil and Natural Gas Properties
	The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center.
	Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.
	Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations.
	In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.
	The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2014 and 2013 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price.
	Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered.
	The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted.
	Asset Retirement Obligation
	Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations.
	Furniture and Equipment
	Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years.
	Capitalized Interest
	The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The Notes and Revolving Credit Facility were included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2014. Currently, the Company only capitalizes interest on the Notes. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $4.3 million, $3.3 million and $1.9 million for 2014, 2013 and 2012, respectively.
	Fair Value of Financial Instruments
	The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value.
	Deferred Financing Costs
	Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense.
	The following table indicates deferred charges and related accumulated amortization as of the dates indicated:
		As of December 31,
		2014			2013
	Deferred charges	$	3,664		$	3,269
	Accumulated amortization	(1,078		)	(319		)
	Deferred charges, net	$	2,586		$	2,950
	Derivative Instruments and Hedging Activity
	The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.”
	The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in (loss) gain on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in (loss) gain on commodity derivatives contracts in the Company’s consolidated statement of operations.
	Stock-Based Compensation
	The Company reports compensation expense for restricted common stock, performance based units (“PBUs”) and stock options granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.
	Stock-based compensation cost for restricted shares is estimated at the grant date based on the award's fair value, which is equal to the prior day's closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant based on the award's fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. The Company did not award any stock option grants during 2014, 2013 or 2012.
	Treasury Stock
	Treasury stock purchases are recorded at cost as a reduction to common stock. Shares of common stock are canceled upon repurchase.
	Revenue Recognition
	The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company's NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company's wet gas production. The Company's reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which the Company is credited under its sales contracts. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2014 and 2013.
	The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, oil, condensate, natural gas and NGLs volumes sold are not significantly different from the Company’s share of production.
	The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet.
	Deferred Income Taxes
	Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.
	Comprehensive Income
	Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Company has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.
	Earnings or Loss per Share
Basic earnings or loss per share is computed on the basis of the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed based upon the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of stock options, unvested restricted shares and PBUs.
Joint Venture Operations
The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.
Foreign Currency Exchange
The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the Company is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction.
All of the Company’s operations are conducted in U.S. dollars. The Company owns immaterial non-operating working interests in two natural gas wells located in Alberta, Canada, from which it has received no revenue since January 1, 2012.
Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations.
Recent Accounting Developments
The following recently issued accounting pronouncements have been adopted or may impact us in future periods:
Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.
Income taxes. In July 2013, the FASB issued an amendment to previously issued guidance regarding the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The amendment requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except as follows. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and should be made presuming disallowance of the tax position at the reporting date. This amendment does not require new recurring disclosures. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this guidance did not impact the Company's operating results, financial position or cash flows.

Property_Plant_And_Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant And Equipment	Property, Plant and Equipment
	The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of West Virginia, Pennsylvania, Oklahoma and Texas. The Company sold substantially all of its interest in East Texas on October 2, 2013, with an effective date of January 1, 2013. The Company's total property, plant and equipment consists of the following:
		December 31,
		2014				2013
		(in thousands)
	Oil and natural gas properties, full cost method of accounting:
	Unproved properties	$	128,274			$	96,220
	Proved properties	1,124,367				935,773
	Total oil and natural gas properties	1,252,641				1,031,993
	Furniture and equipment	3,010				2,691
	Total property and equipment	1,255,651				1,034,684
	Impairment of proved natural gas and oil properties	(337,939		)		(337,939		)
	Accumulated depreciation, depletion and amortization	(225,412		)		(179,232		)
	Total accumulated depreciation, depletion and amortization	(563,351		)		(517,171		)
	Total property and equipment, net	$	692,300			$	517,513
	Included in the Company's oil and natural gas properties are asset retirement costs of $2.4 million and $3.4 million as of December 31, 2014 and 2013, respectively.
	The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:
		December 31,
		2014				2013
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	29,193			$	4,774
	Acreage acquisition costs	91,362				86,097
	Capitalized interest	7,719				5,349
	Total unproved properties excluded from amortization	$	128,274			$	96,220
	For the years ended December 31, 2014 and 2013, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $3.3 million and $20.5 million of unproved properties to proved properties for the years ended December 31, 2014 and 2013, respectively.
	The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation dictates that the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely. The 12-month unweighted arithmetic average of the first-day-of-the-month prices are adjusted for basis and quality differentials in determining the present value of the reserves. The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted:
			2014
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)						$	4.35		$	4.24	$	4.1	$	3.99
	West Texas Intermediate oil price (per Bbl)(1)						$	94.99		$	99.08	$	100.11	$	98.3
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
			2013
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)						$	3.67		$	3.61	$	3.44	$	2.95
	West Texas Intermediate oil price (per Bbl)(1)						$	96.78		$	91.69	$	88.13	$	89.17
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
			2012
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)						$	2.76		$	2.83	$	3.15	$	3.73
	West Texas Intermediate oil price (per Bbl)(1)						$	91.21		$	91.48	$	92.17	$	94.65
	Impairment recorded (pre-tax) (in thousands)		$	150,787			$	—		$	78,054	$	72,733	$	—
	_________________________________
	-1	For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.
	Future declines in the 12-month average of oil, condensate, natural gas and NGLs prices could result in the recognition of future ceiling impairments.
	Chesapeake Acquisition
	On March 28, 2013, Gastar USA entered into a Purchase and Sale Agreement by and among the Chesapeake Parties and Gastar USA (the “Chesapeake Purchase Agreement”). Pursuant to the Chesapeake Purchase Agreement, Gastar USA was to acquire approximately 157,000 net acres of Oklahoma oil and gas leasehold interests from the Chesapeake Parties, including production from interests in 206 producing wells located in Oklahoma (the “Chesapeake Assets”). The Chesapeake Purchase Agreement contained customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in the Chesapeake Purchase Agreement. On June 7, 2013, the parties to the Chesapeake Purchase Agreement entered into an Amendment to Purchase and Sale Agreement, dated June 7, 2013, in order to revise the description of the properties to be acquired and to evidence the withdrawal of Arcadia Resources, L.P. and Jamestown Resources, L.L.C. from the Chesapeake Purchase Agreement. Pursuant to the Chesapeake Purchase Agreement, as amended, on June 7, 2013, Gastar USA completed the acquisition of the Chesapeake Assets for a final adjusted purchase price of $69.4 million.
	Upon completion of the initial purchase price allocation, as of June 7, 2013, the Company reviewed and verified its assessment, including the identification and valuation of assets acquired. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $2.1 million of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the Chesapeake Assets resulted in a fair market valuation of $113.1 million. With the completion of the asset valuation during the fourth quarter of 2013, the Company recorded the deferred tax attributes associated with the transaction. As a result of incorporating the final valuation information into the purchase price allocation, a bargain purchase gain of $27.7 million, net of $16.0 million of income tax expense, was recognized in the accompanying consolidated statements of operations for the year ended December 31, 2013. The bargain purchase gain was primarily attributable to the non-strategic nature of the divestiture to the seller, coupled with favorable economic trends in the industry and the geographic region in which the Chesapeake Assets are located. The Company believes the estimates used in the fair market valuation and purchase price allocation are reasonable and that the significant effects of the acquisition are properly reflected.
	The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Chesapeake acquisition (in thousands):
	Consideration:
	Cash consideration		$	69,371
	Fair Value of Liabilities Assumed:
	Deferred tax liability		16,042
	Total purchase price plus liabilities assumed		$	85,413
	Estimated Fair Value of Assets Acquired:
	Unproved properties		$	86,327
	Proved properties		26,756
	Total assets acquired		$	113,083
	Bargain purchase gain		$	27,670
	Hunton Joint Venture AMI Election
	Effective July 1, 2013, Gastar USA's working interest partner in its original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties that Gastar USA acquired pursuant to the Chesapeake Purchase Agreement for a total payment of $11.8 million, of which $133,000 was deemed to be a reimbursement of transaction and integration costs associated with the acquisition and was recorded as a reduction of general and administrative expense.
	Hunton Divestiture
	On July 2, 2013, Gastar USA entered into a purchase and sale agreement with Newfield, dated July 2, 2013, pursuant to which Newfield acquired approximately 76,000 net undeveloped acres of oil and gas leasehold interests in Kingfisher and Canadian Counties, Oklahoma from Gastar USA and Gastar USA acquired approximately 1,850 net acres of Oklahoma oil and gas leasehold interests from Newfield. The transaction closed on August 6, 2013 for a net cash purchase price of approximately $57.0 million, adjusted for an acquisition effective date of May 1, 2013. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.
	WEHLU Acquisition
On September 4, 2013, Gastar USA entered into a Purchase and Sale Agreement, dated September 4, 2013, by and among the Lime Rock Parties and Gastar USA (the “WEHLU Purchase Agreement”). Pursuant to the WEHLU Purchase Agreement, Gastar USA acquired a 98.3% working interest (80.5% net revenue interest) in 24,000 net acres of the West Edmond Hunton Lime Unit (“WEHLU”) located in Kingfisher, Logan and Oklahoma Counties, Oklahoma, all of which is held by production (“WEHLU Assets”). Pursuant to the WEHLU Purchase Agreement, Gastar USA completed the acquisition of the WEHLU Assets on November 15, 2013 for an adjusted cash purchase price of $177.8 million, (the “WEHLU Acquisition”).
The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $286,000 of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the WEHLU Assets resulted in a fair market valuation of $176.8 million. As the fair market valuation varied less than 1% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation.
The following table summarizes the estimated fair value of the assets acquired in connection with the WEHLU Acquisition (in thousands):
Consideration:
Cash consideration		$	177,778
Estimated Fair Value of Assets Acquired:
Unproved properties		$	13,026
Proved properties		164,752
Total assets acquired		$	177,778
Chesapeake and WEHLU Acquisition Unaudited Pro Forma Operating Results
The following unaudited pro forma results for the years ended December 31, 2013 and 2012 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of each respective period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.
		For the Years Ended December 31,
		2013				2012
		(in thousands, except per share data)
		(Unaudited)
Revenues		$	132,721			$	97,760
Net Loss		$	(4,836	)		$	(175,809	)
Loss per share:
Basic		$	(0.08	)		$	(2.77	)
Diluted		$	(0.08	)		$	(2.77	)
The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Chesapeake and WEHLU Acquisitions occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information.
The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Chesapeake and WEHLU Acquisitions are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes.
		Year Ended December 31, 2013
		(in thousands)
Revenues		$	11,292
Excess of revenues over direct operating expenses		$	7,591
Hilltop Area, East Texas Sale
On April 19, 2013, Gastar Exploration Texas, LP (“Gastar Texas”) and Gastar USA entered into a Purchase and Sale Agreement by and among Gastar Texas, Gastar USA and Cubic Energy, Inc. (“Cubic Energy”) (the “East Texas Sale Agreement”). Pursuant to the East Texas Sale Agreement, as amended, on October 2, 2013, Cubic Energy acquired from Gastar Texas approximately 31,800 gross (16,300 net) acres of leasehold interests in the Hilltop area of East Texas in Leon and Robertson Counties, Texas, including production from interests in producing wells, for adjusted net proceeds of approximately $42.9 million. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.
Atinum Joint Venture
In September 2010, Gastar USA entered into a joint venture (the “Atinum Joint Venture”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum”), a Korean investment firm. Pursuant to the agreement, at the closing of the transactions on November 1, 2010, Gastar USA assigned to Atinum an initial 21.43% interest in all of its existing Marcellus Shale assets in West Virginia and Pennsylvania, which consisted of approximately 37,600 gross (34,200 net) acres and a 50% working interest in 16 producing shallow conventional wells and one non-producing vertical Marcellus Shale well (the “Atinum Joint Venture Assets”). Atinum paid Gastar USA approximately $30.0 million in cash at the closing and paid an additional $40.0 million of Gastar USA's share of drilling costs over time in the form of a “drilling carry.” Upon completion of the funding of the drilling carry, Gastar USA made additional assignments to Atinum in early 2012 as a result of which Atinum owns a 50% interest in the Atinum Joint Venture Assets. The terms of the drilling carry required Atinum to fund its ultimate 50% share of drilling, completion and infrastructure costs along with 75% of Gastar USA’s ultimate 50% share of those same costs until the $40.0 million drilling carry had been satisfied. As of December 31, 2011, Atinum had completed the funding of the $40.0 million drilling carry. Subsequent to December 31, 2011, Atinum funds only its 50% share of costs.
The Atinum Joint Venture pursued an initial three-year development program that called for the partners to drill a minimum of 60 horizontal wells by year-end 2013. Due to natural gas price declines, Atinum and Gastar USA agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 wells to 51 wells. At December 31, 2014, 67 gross (32.0 net) operated Marcellus Shale wells and one gross (0.5 net) gross operated Utica Shale well were capable of production under the Atinum Joint Venture. The Atinum Joint Venture agreement expires on November 1, 2015.
Subsequent to June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, Gastar USA acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay Gastar USA on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt
	Second Amended and Restated Revolving Credit Facility
	On June 7, 2013, the Company entered into the Second Amended and Restated Credit Agreement among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). At the Company's election, borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent (ii) the federal funds rate plus 50 basis points or (iii) LIBOR plus 1.0%. The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base and subject to adjustments based on the Company's leverage ratio. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity of November 14, 2017.
	The Revolving Credit Facility will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by the Company and its subsidiaries, excluding de minimis value properties as determined by the lender. The Revolving Credit Facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of any foreign subsidiary of the Company.
	The Revolving Credit Facility contains various covenants, including among others:
	•	Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments;
	•	Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted;
	•	Maintenance of a maximum ratio of indebtedness to EBITDA of not greater than 4.0 to 1.0, subject to the modifications in Amendment No. 5 set forth below; and
	•	Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0, subject to the modifications in Amendment No. 5 set forth below.
	All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including among others:
	•	Failure to make payments;
	•	Non-performance of covenants and obligations continuing beyond any applicable grace period; and
	•	The occurrence of a change in control of the Company, as defined in the Revolving Credit Facility.
	On March 9, 2015, the Company, together with the parties thereto, entered into a Master Assignment, Agreement and Amendment No. 5 (“Amendment No. 5”) to Second Amended and Restated Credit Agreement. Amendment No. 5 amended the Revolving Credit Facility to, among other things, (i) increase the borrowing base from $145.0 million to $200.0 million, (ii) adjust the leverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to September 30, 2016, to 5.25 to 1.00; for the fiscal quarter ending on September 30, 2016, to 5.00 to 1.00; for the fiscal quarter ending on December 31, 2016, to 4.75 to 1.00; for the fiscal quarter ending on March 31, 2017, to 4.25 to 1.00; and for each fiscal quarter ending on or after June 30, 2017, to 4.00 to 1.00, (iii) adjust the interest coverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to March 31, 2016, to 2.00 to 1.00 and for each fiscal quarter ending on or after March 31, 2016, to 2.50 to 1.00, and (iv) add the senior secured leverage ratio covenant, such ratio not to exceed, (a) for each fiscal quarter ending on or after March 31, 2015 but prior to June 30, 2016, 2.25 to 1.00 and (b) for each fiscal quarter ending on or after June 30, 2016, 2.00 to 1.00 provided that this senior secured leverage ratio shall cease to apply commencing with the first fiscal quarter end occurring after June 30, 2016 for which the total leverage ratio is equal to or less than 4.00 to 1.00.
	Borrowing base re-determinations are scheduled semi-annually in May and November of each calendar year. The Company and its lenders may each request one additional unscheduled re-determination during any six-month period between scheduled re-determinations. At December 31, 2014, the Revolving Credit Facility had a borrowing base of $145.0 million, with $45.0 million of borrowings outstanding and availability of $100.0 million. Effective March 9, 2015, the borrowing base was increased to $200.0 million. The next regularly scheduled re-determination is set for November 2015. Future increases in the borrowing base in excess of the original $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets as defined in the Notes agreement (as discussed below in “Senior Secured Notes”).
	At December 31, 2014, the Company was in compliance with all financial covenants under the Revolving Credit Facility.
	Senior Secured Notes
	The Company has $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Notes”) outstanding under an indenture (the “Indenture”) by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. The Notes will mature on May 15, 2018.
	In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require the Company to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase.
	The Notes will be guaranteed, jointly and severally, on a senior secured basis by certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of the Company's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of the Company's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to the Company's unsecured indebtedness and effectively subordinated to the Company's and Guarantors' indebtedness under the Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation.
	The Indenture contains covenants that, among other things, limit the Company's ability and the ability of its subsidiaries to:
	•	Transfer or sell assets or use asset sale proceeds;
	•	Pay dividends or make distributions, redeem subordinated debt or make other restricted payments;
	•	Make certain investments; incur or guarantee additional debt or issue preferred equity securities;
	•	Create or incur certain liens on the Company's assets;
	•	Incur dividend or other payment restrictions affecting future restricted subsidiaries;
	•	Merge, consolidated or transfer all or substantially all of the Company's assets;
	•	Enter into certain transactions with affiliates; and
	•	Enter into certain sale and leaseback transactions.
	These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture.
	On May 15, 2013 and November 15, 2013, in connection with each issuance and sale of the Notes, the Company and each of the Guarantors entered into Registration Rights Agreements (together, the “Registration Rights Agreements”) with Imperial Capital, LLC, as representative of the initial purchasers. Under the Registration Rights Agreement, the Company agreed, subject to certain exceptions, to (i) file a registration statement with the SEC with respect to an exchange of the Notes for new notes having terms substantially identical in all material respects to the Notes (except that the exchange notes will not contain terms relating to transfer restrictions), (ii) use its reasonable best efforts to cause the exchange offer registration statement to be declared effective under the Securities Act of 1933, as amended, within 360 days after the issue date of the Notes, (iii) as soon as practicable after the effectiveness of the exchange offer registration statement, offer the exchange notes in exchange for the Notes, and (iv) keep the registered exchange offer open for not less than 30 days (or longer if required by applicable law) after the date of the registered exchange offer is mailed to the holders of the Notes. The Company and the Guarantors also agreed to file a shelf registration statement for the resale of the Notes if an exchange offer cannot be effected within the time period specified above and in other circumstances. Pursuant to the Registration Rights Agreements entered into in connection with the offering and sale of the Notes, in May 2014, holders of the Notes exchanged their notes for registered notes with the same terms.
	At December 31, 2014, the Notes reflected a balance of $315.3 million, net of unamortized discounts of $9.7 million, on the consolidated balance sheets.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Asset Retirement Obligation
	A summary of the activity related to the asset retirement obligation is as follows:
		For the years ended December 31,
		2014			2013			2012
		(in thousands)
	Asset retirement obligation, beginning of year	$	6,063		$	6,963		$	8,275
	Liabilities incurred during period	305			3,416			271
	Liabilities settled during period	(704		)	(126		)	(297		)
	Accretion expense	506			468			388
	Revision in previous estimates and other	32			60			553
	Deletions related to property disposals	(645		)	(4,718		)	(2,227		)
	Asset retirement obligation, end of year	$	5,557		$	6,063		$	6,963
	As of December 31, 2014, the current portion of the Company's asset retirement obligation was $82,000 and was recorded in current liabilities on the consolidated balance sheet.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements
	The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties, which are Level 3 inputs. For the years ended December 31, 2014 and 2013, management's evaluation of unproved properties resulted in an impairment. Due to continued low natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $3.3 million and $20.5 million of unproved properties to proved properties for the years ended December 31, 2014 and 2013, respectively. As no other fair value measurements are required to be recognized on a non-recurring basis at December 31, 2014, no additional disclosures are provided at December 31, 2014.
	As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:
	•	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds.
	•	Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.
	•	Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge oil, natural gas and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.
	As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets.
	Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2014 and 2013 periods.
	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013:
		Fair value as of December 31, 2014
		Level 1		Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	11,008	$	—		$	—		$	11,008
	Commodity derivative contracts	—		—			27,502			27,502
	Liabilities:
	Commodity derivative contracts	—		—			—			—
	Total	$	11,008	$	—		$	27,502		$	38,510
		Fair value as of December 31, 2013
		Level 1		Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	32,393	$	—		$	—		$	32,393
	Restricted cash	—		—			—			—
	Commodity derivative contracts	—		—			7,545			7,545
	Liabilities:
	Commodity derivative contracts	—		—			(3,781		)	(3,781		)
	Total	$	32,393	$	—		$	3,764		$	36,157
	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2014 and 2013. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2014 and 2013.
		For the years ended December 31,
		2014		2013
		(in thousands)
	Balance at beginning of period	$	3,764	$	6,465
	Total gains (losses)
	included in earnings	19,569		(4,752		)
	Purchases	369		9,772
	Issuances	—		(2,308		)
	Settlements(1)	3,800		(5,413		)
	Balance at end of period	$	27,502	$	3,764
	The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2014 and 2013	$	23,902	$	(9,967	)
	_________________________________
	-1	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations.
	At December 31, 2014, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at December 31, 2014 was $330.6 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximated the current market rate (Level 2). The estimated fair value of the Company’s long-term debt at December 31, 2013 was $324.6 million based on quoted market prices of the Notes (Level 1).
	The Company has consistently applied the valuation techniques discussed above in all periods presented.
	The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivative Instruments and Hedging Activity.”

Derivative_Instruments_And_Hed

Derivative Instruments And Hedging Activity	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments And Hedging Activity	Derivative Instruments and Hedging Activity
	The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk.
	All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in (loss) gain on commodity derivatives contracts. For the year ended December 31, 2014, the Company reported a gain of $23.9 million in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. For the years ended December 31, 2013 and 2012, the Company reported losses of $10.0 million and $5.6 million, respectively, in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments.
	As of December 31, 2014, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume			Volume			Price
					(in MMBtu's)
	2015(1)		Protective spread		10,000			900,000			$	4.46			$	—	$	3.7	$	—
	2015(1)		Call spread		10,000			900,000			$	—			$	—	$	—	$	5
	2015		Fixed price swap		400			146,000			$	4			$	—	$	—	$	—
	2015		Fixed price swap		2,500			912,500			$	4.06			$	—	$	—	$	—
	2015		Protective spread		2,600			949,000			$	4			$	—	$	3.25	$	—
	2015(1)		Producer three-way collar		3,750			337,500			$	—			$	4.6	$	3.5	$	5.34
	2015(1)		Producer three-way collar		2,500			337,500			$	—			$	4.4	$	3.65	$	5
	2015		Producer three-way collar		2,000			760,000			$	—			$	4	$	3.25	$	4.58
	2015		Basis swap(2)		2,500			912,500			$	(1.12	)		$	—	$	—	$	—
	2015		Basis swap(2)		2,500			912,500			$	(1.11	)		$	—	$	—	$	—
	2015		Basis swap(2)		2,500			912,500			$	(1.14	)		$	—	$	—	$	—
	2015(3)		Protective spread		5,000			1,375,000			$	4			$	—	$	3.25	$	—
	2015(3)		Producer three-way collar		2,500			687,500			$	—			$	3.7	$	3	$	4.09
	2015(3)		Producer three-way collar		5,000			1,375,000			$	—			$	3.77	$	3	$	4.11
	2016		Protective spread		2,000			732,000			$	4.11			$	—	$	3.25	$	—
	_______________________________
	-1	For the period January to March 2015.
	-2	Represents basis swaps at the sales point of Dominion South.
	-3	For the period April to December 2015.
	As of December 31, 2014, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume (1)			Volume			Price
					(in Bbls)
	2015(2)		Costless collar		400			72,400			$	—			$	85	$	—	$	96.5
	2015(2)		Costless collar		366			66,300			$	—			$	85	$	—	$	97.8
	2015(2)		Costless collar		150			27,150			$	—			$	85	$	—	$	96.25
	2015(3)		Costless three-way collar		400			73,600			$	—			$	85	$	70	$	96.5
	2015(3)		Costless three-way collar		325			59,800			$	—			$	85	$	65	$	97.8
	2015(3)		Costless three-way collar		50			9,200			$	—			$	85	$	65	$	96.25
	2015(2)		Put spread		700			126,700			$	—			$	90	$	70	$	—
	2015		Put spread		250			91,250			$	—			$	89	$	69	$	—
	2015(3)		Put spread		600			110,400			$	—			$	87	$	67	$	—
	2016		Costless three-way collar		275			100,600			$	—			$	85	$	65	$	95.1
	2016		Costless three-way collar		330			120,780			$	—			$	80	$	65	$	97.35
	2016		Put spread		550			201,300			$	—			$	85	$	65	$	—
	2016		Put spread		300			109,800			$	—			$	85.5	$	65.5	$	—
	2017		Costless three-way collar		280			102,200			$	—			$	80	$	65	$	97.25
	2017		Costless three-way collar		242			88,150			$	—			$	80	$	60	$	98.7
	2017		Put spread		500			182,500			$	—			$	82	$	62	$	—
	2018(4)		Put spread		425			103,275			$	—			$	80	$	60	$	—
	_______________________________
	-1	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
	-2	For the period January to June 2015.
	-3	For the period July to December 2015.
	-4	For the period January to August 2018.
	As of December 31, 2014, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base
					Daily			Notional			Fixed
					Volume			Volume			Price
					(in Bbls)
	2015(1)		Fixed price swap		250			68,750			$	45.61
	_______________________________
	-1	For the period April to December 2015.
	As of December 31, 2014, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.
	In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period January 2014 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company began amortizing the deferred put premium liabilities in December 2013. The following table provides information regarding the deferred put premium liabilities for the periods indicated:
	For the Years Ended December 31,
	2014				2013
	(in thousands)
Current commodity derivative premium put payable	$	2,481			$	145
Long-term commodity derivative premium payable	4,702				7,000
Total unamortized put premium liabilities	$	7,183			$	7,145
	For the Year December 31, 2014
	(in thousands)
Put premium liabilities, beginning balance	$	7,145
Less:
Amortization of put premium liabilities	(145		)
Additional put premium liabilities	183
Put premium liabilities, ending balance	$	7,183
The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2014:
	Amortization
	(in thousands)
January to December 2015	$	2,481
January to December 2016	2,408
January to December 2017	1,460
January to August 2018	834
Total unamortized put premium liabilities	$	7,183
Additional Disclosures about Derivative Instruments and Hedging Activities
The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments:
	Fair Values of Derivative Instruments
	Derivative Assets (Liabilities)
			Fair Value
			December 31,
	Balance Sheet Location		2014				2013
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets		$	19,687			$	—
Commodity derivative contracts	Other assets		7,815				7,545
Commodity derivative contracts	Current liabilities		—				(3,403		)
Commodity derivative contracts	Long-term liabilities		—				(378		)
Total derivatives not designated as hedging instruments			$	27,502			$	3,764
			Amount of Gain (Loss)
			Recognized in Income on
			Derivatives For the Years Ended December 31,
	Location of Gain (Loss) Recognized in		2014				2013				2012
	Income on Derivatives
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Gain (loss) on commodity derivatives contracts		$	19,569			$	(4,752	)		$	7,422
Commodity derivative contracts	Interest expense		—				—				(186		)
Total			$	19,569			$	(4,752	)		$	7,236

Capital_Stock

Capital Stock	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Capital Stock	Capital Stock
	Common Stock
	On November 14, 2013, Parent changed its jurisdiction of incorporation to the State of Delaware and entered into new articles of incorporation pursuant to which 275,000,000 shares of Parent's common stock, par value $0.001 per share, are authorized for issuance. Prior to November 14, 2013, Parent’s articles of incorporation allowed Parent to issue an unlimited number of common shares without par value.
	At December 31, 2013 and 2012, all 750 shares of Gastar USA's common stock were held by Parent. On May 24, 2011, Gastar USA converted from a Michigan corporation to a Delaware corporation (the “Conversion”). Following the Conversion, Gastar USA’s Delaware certificate of incorporation allowed Gastar USA to issue 1,000 shares of common stock, without par value. In connection with the Conversion, the Parent’s 750 shares of common stock in the Michigan corporation were converted to 750 shares of common stock in the new Gastar USA Delaware corporation.
	On October 25, 2013, Gastar USA filed an Amended and Restated Certificate of Incorporation (the “A&R Certificate”) with the Secretary of State of the State of Delaware. Under the A&R Certificate, the capital stock authorized for issuance was increased from 1,000 shares of common stock, without par value, to 275,000,000 shares of common stock, par value $0.001 per share.
	On January 31, 2014, Parent entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Parent merged with and into Gastar USA, a direct subsidiary of Parent, as part of a reorganization to eliminate Parent's holding company corporate structure. Pursuant to the Merger Agreement, shares of Parent's common stock were converted into the right to receive an equal number of shares of common stock of Gastar USA, which together with its subsidiary, owns and continues to conduct business in substantially the same manner as it was being conducted by Parent and its subsidiaries immediately prior to the merger.
	On September 24, 2014, the Company sold 17,000,000 shares of its common stock in an underwritten public offering pursuant to the Company's effective Registration Statement on Form S-3 at a price of $6.25 per share, or $106.3 million before offering costs and expenses. The Company received approximately $101.3 million of proceeds from the offering, net of estimated offering costs and expenses of approximately $5.0 million.
	Preferred Stock
	Prior to the Conversion, Gastar USA’s articles of incorporation did not authorize issuance of preferred stock.
	Following the Conversion, Gastar USA’s Delaware certificate of incorporation allowed Gastar USA to issue 10,000,000 shares of preferred stock, par value $0.01 per share. The preferred stock was permitted to be issued from time to time in one or more series. Gastar USA’s Board of Directors (the “Gastar USA Board”) was authorized to fix the number of shares of any series of preferred stock and to determine the designation of any such series. The Gastar USA Board was also authorized to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued series of preferred stock and, within the limits and restrictions stated in any resolution or resolutions of the Gastar USA Board originally fixing the number of shares constituting any series, to increase or decrease (but not below the number of shares of any such series outstanding) the number of shares of any series subsequent to the issues shares of that series). Pursuant to the A&R Certificate, the number of shares of preferred stock authorized for issuance was increased to 40,000,000 shares.
	Series A Preferred Stock
	On June 23, 2011, Gastar USA sold an aggregate of 646,295 shares of its 8.625% Series A Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series A Preferred Stock”) through a best efforts underwritten public offering. The net proceeds to Gastar USA were approximately $13.6 million after deducting underwriting discounts, commissions and offering expenses.
	On June 29, 2011, Gastar USA entered into an at-the-market sales agreement (“ATM Agreement”) with McNicoll, Lewis & Vlak LLC (“MLV”). According to the provisions of the ATM agreement, Gastar USA may offer and sell from time to time up to 3,400,000 shares of Series A Preferred Stock through MLV, as its sales agent. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between Gastar USA and MLV.
	For the year ended December 31, 2014, Gastar USA sold 86,840 shares of Series A Preferred Stock under the ATM Agreement for net proceeds of $2.1 million, resulting in 4,045,000 total shares of Series A Preferred Stock issued for total net proceeds, inception to date, of $78.8 million at December 31, 2014.
	The Series A Preferred Stock is subordinated to all of Gastar USA’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock.
	The Series A Preferred Stock cannot be converted into common stock of Gastar USA or the Company, but may be redeemed by Gastar USA, at Gastar USA’s option for $25.00 per share plus any accrued and unpaid dividends or in certain circumstances prior to such date as a result of a change in control. Following a change in control, Gastar USA will have the option to redeem the Series A Preferred Stock, in whole but not in part, within 90 days after the date on which the change in control occurs, for cash at $25.00 per share, plus accrued and unpaid dividends (whether or not declared), up to the redemption date.
	There is no mandatory redemption of the Series A Preferred Stock.
	Gastar USA pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the years ended December 31, 2014, 2013 and 2012, Gastar USA paid dividends of $8.7 million, $8.5 million and $7.1 million, respectively.
	Series B Preferred Stock
	On October 29, 2013, Gastar USA sold 2,000,000 shares of its 10.75% Series B Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series B Preferred Stock”), in an underwritten public offering. On November 1, 2013, the underwriters partially exercised their option to purchase additional shares of Series B Preferred Stock and purchased an additional 140,000 shares of Series B Preferred Stock. The issuance of the 2,140,000 shares of Series B Preferred Stock closed on November 7, 2013 with Gastar USA receiving net proceeds of approximately $50.1 million after deducting underwriting commissions and offering expenses.
	The Series B Preferred Stock rank senior to Gastar USA’s common stock and on parity with its 8.625% Series A Cumulative Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of Gastar USA’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock.
	Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at Gastar USA’s option for $25.00 per share in cash. Following a change in ownership or control, Gastar USA will have the option to redeem the Series B Preferred Stock, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If Gastar USA does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into up to and aggregate of 11.5207 shares of Gastar USA’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If Gastar USA exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption.
	There is no mandatory redemption of the Series B Preferred Stock.
	Gastar USA pays cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the years ended December 31, 2014 and 2013, Gastar USA paid dividends of $5.8 million and $847,000, respectively.
	Other Share Issuances
	The following table provides information regarding the issuances and forfeitures of the Company's common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated:
		For the Years Ended December 31,
		2014	2013
	Other stock issuances:
	Shares of restricted common stock granted	601,473	2,288,179
	Shares of restricted common stock vested	1,915,242	762,682
	Shares of common stock issued pursuant to PBUs vested, net of forfeitures	472,189	—
	Stock options exercised	7,500	10,000
	Shares of restricted common stock surrendered upon vesting/exercise (1)	612,612	224,500
	Shares of restricted common stock forfeited	47,398	512,862
	_______________________________
	-1	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period.
	On June 7, 2012, Parent's stockholders voted to approve the Second Amendment to Parent's 2006 Long-Term Stock Incentive Plan. This amendment, effective June 3, 2012, increased the total number of shares available for issuance under the plan from 6,000,000 shares to 11,000,000 shares. In connection with the merger, Parent's 2006 Long-Term Stock Incentive Plan was assumed by Gastar Exploration Inc. and, effective as of the merger, was amended, restated and renamed the “Gastar Exploration Inc. Long-Term Incentive Plan” (as amended, the “LTIP”). On June 12, 2014, the Company's stockholders approved an amendment and restatement to the LTIP, effective April 24, 2014, to, among other things, increase the number of shares reserved for issuance under the LTIP by 3,000,000 shares. There were 4,561,508 shares available for issuance under the LTIP at December 31, 2014.
	Shares Reserved
	At December 31, 2014, the Company had 866,600 shares of common stock reserved for the exercise of stock options and 990,658 shares reserved for the settlement of PBUs.
	Shares Owned by Chesapeake Energy Corporation
	On March 28, 2013, the Company entered into a Settlement Agreement, dated March 28, 2013, between Chesapeake Exploration, L.L.C. and Chesapeake Energy Corporation (collectively, “Chesapeake”) and the Company, Gastar Texas and Gastar Texas, LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding shares of common stock of Parent held by Chesapeake Energy Corporation upon the closing of the stock repurchase and settlement on June 7, 2013.

Equity_Compensation_Plans

Equity Compensation Plans	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Compensation Plans	Equity Compensation Plans
	Share-Based Compensation Plan
	The vesting period for recent restricted common stock grants has been from two to four years, but generally has been over three years, vesting annually from the date of grant in equal proportions.
	On June 12, 2014, the Company's stockholders approved the Amended and Restated Gastar Exploration Inc. Long-Term Incentive Plan (the “LTIP”). The LTIP permits us to issue stock options, stock appreciation rights, bonus stock awards and any other type of award (including performance-based units, or “PBU’s”), which are consistent with the LTIP’s purpose to directors, officers and employees of the Company and its subsidiaries.
	At December 31, 2014, 4,561,508 shares of common stock were available for future stock-based compensation grants under the LTIP. All shares of common stock issued upon the exercise of stock option grants or vesting of restricted stock grants and PBUs are authorized, issued by the Company and are fully paid and non-assessable.
	Determining Fair Value of Stock Options
	There were no stock options granted during the years ended December 31, 2014, 2013 and 2012. However, in prior years, the Company issued stock options as a component of its equity compensation program. As of December 31, 2014, all stock options were vested. In determining the fair value of stock option grants, the Company utilized the following assumptions:
	Valuation and Amortization Method. The Company estimates the fair value of stock option awards using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method.”
	Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding. The Company determined the expected life to be 6.25 years, based on historical information, for all stock options issued with four-year vesting periods and ten-year grant expirations.
	Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of the Company's common stock at the beginning of the quarter in which the stock option is granted. The volatility is based on weighted average historical movements of the Company's common stock price on the NYSE MKT LLC over a period that approximates the expected life.
	Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.
	Expected Dividend Yield. The Company has not paid any cash dividends on its common stock and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.
	Expected Forfeitures. Forfeitures of unvested stock options and restricted common shares are calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. For 2014, 2013 and 2012, the Company used forfeiture rates in determining compensation expense of 25.5%, 14% and 15.5%, respectively.
	The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model.
	The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated:
		For the Years Ended December 31,
		2014				2013			2012
		(in thousands, except per share data)
	Weighted average grant date fair value per stock option granted	$	—			$	—		$	—
	Intrinsic value of stock options exercised (1)	$	28			$	19		$	2
	Grant date fair value of stock options vested	$	27			$	88		$	117
	_______________________________
	-1	Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.
	Stock Option Activity
	The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2014:
		Shares			Weighted Average			Weighted Average		Aggregate
					Exercise Price			Remaining		Intrinsic Value
					per Share			Contractual Term		(in thousands)
								(in years)
	Outstanding at December 31, 2013	874,100			$	11.68
	Granted	—			—
	Exercised	(7,500	)		2.6
	Canceled/Expired	—			—
	Forfeited	—			—
	Outstanding at December 31, 2014	866,600			$	11.75
	Options vested and exercisable at December 31, 2014	866,600			$	11.75		2.19		$	—
		Shares			Weighted Average			Weighted Average				Weighted Average	Aggregate
					Fair Value			Exercise Price				Remaining	Intrinsic Value
					per Share			per Share				Contractual Term	(in thousands)
												(in years)
	Outstanding non-vested options at December 31, 2013	10,000			$	2.74
	Granted	—			—
	Vested	(10,000	)		2.74
	Forfeited	—			—
	Outstanding non-vested options at December 31, 2014	—			$	—		$	—			0	$	—
	There was no unrecognized expense as of December 31, 2014 for all outstanding options.
	Restricted Share Activity
	The Company has granted restricted shares of common stock which vest based upon continued service or certain other events. Prior to December 31, 2014, the vesting period for recent restricted common stock grants has been from two to four years, but generally has been over three years, vesting annually from the date of grant in equal proportions. The following table summarizes information related to restricted shares at December 31, 2014:
		Shares			Weighted  Average			Weighted Average		Aggregate
					Fair Value			Remaining		Intrinsic Value (in thousands)
					per Share			Contractual Term
								(in years)
	Outstanding non-vested restricted shares at December 31, 2013	3,773,081			$	1.82
	Granted	601,473			5.85
	Vested	(1,915,242	)		1.83
	Forfeited	(47,398	)		3.76
	Outstanding non-vested restricted shares at December 31, 2014	2,411,914			$	2.79		8.11		$	5,813
	The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated:
		For the Years Ended December 31,
		2014				2013			2012
		(in thousands, except per share data)
	Weighted average grant date fair value per restricted share	$	5.85			$	1.3		$	2.09
	Total fair value of restricted shares vested	$	3,497			$	2,725		$	2,492
	Unrecognized compensation expense as of December 31, 2014 for all outstanding restricted share awards is $1.6 million and will be recognized over a weighted average period of 1.43 years.
Performance Based Units Activity
During 2014 and 2013, a portion of long-term incentive grants were in the form of PBUs. The PBUs represent a contractual right to receive shares of the Company's common stock, an amount of cash equal to the fair market value of a share of the Company's common stock, or a combination of shares of the Company's common stock and cash as of the date of settlement based on the number of PBUs to be settled. The settlement of PBUs may range from 0% to 200% of the targeted number of PBUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PBUs vest equally and settlement is determined annually over a three year period. Any PBUs not vested at each measurement date will expire.
Compensation expense associated with PBUs is based on the grant date fair value of a single PBU as determined using a Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PBUs with shares of the Company's common stock at each measurement date, the PBU awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the PBU award.
The table below provides a summary of PBUs as of the date indicated:
		PBUs			Fair Value per Unit
Unvested PBUs at December 31, 2013		1,065,734			$	1.56
Granted		280,171			7.34
Vested		(355,247	)		1.56
Forfeited		—			—
Unvested PBUs at December 31, 2014		990,658			$	3.19
For the year ended December 31, 2014, the Company recognized $1.7 million of compensation expense associated with the PBUs. As of December 31, 2014, the Company had $1.1 million of total unrecognized expense for the PBUs.
Stock-Based Compensation Expense
For the years ended December 31, 2014, 2013 and 2012, the Company recorded stock-based compensation expense for restricted shares, PBUs, and stock options granted using the fair-value method of $4.9 million, $3.4 million and $3.3 million, respectively. All stock-based compensation costs were expensed and not tax affected, as the Company currently records no U.S. income tax expense.
As of December 31, 2014, the Company had approximately $2.8 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods:
	Amount
	(in thousands)
2015	$	2,034
2016	663
2017	59
Total	$	2,756

Interest_Expense

Interest Expense	12 Months Ended
	Dec. 31, 2014
Interest Expense [Abstract]
Interest Expense	Interest Expense
	The following tables summarize the components of the Company's interest expense for the periods indicated:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Interest expense:
	Cash and accrued	$	28,851		$	14,130		$	1,992
	Amortization of deferred financing costs(1)(2)	3,067			2,322			224
	Capitalized interest	(4,347		)	(3,284		)	(1,946		)
	Total interest expense	$	27,571		$	13,168		$	270
	_______________________________
	-1	The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.”
	-2	The years ended December 31, 2014 and 2013 include $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions
	Chesapeake Energy Corporation
	Chesapeake Energy Corporation acquired 6,781,768 of Parent’s common shares during 2005 to 2007 in a series of private placement transactions. On March 28, 2013, the Company entered into a Settlement Agreement between Chesapeake and the Company, Gastar Texas and Gastar Texas LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding common shares of Parent held by Chesapeake upon the closing of the stock repurchase and settlement on June 7, 2013. For more information, see Note 8. “Capital Stock - Shares Owned by Chesapeake Energy Corporation.”
	Also on March 28, 2013, the Company entered into the Chesapeake Purchase Agreement, pursuant to which Gastar USA acquired the Chesapeake Assets on June 7, 2013. For more information, see Note 3. “Property, Plant and Equipment - Chesapeake Acquisition.”
	As of December 31, 2014, Chesapeake Energy Corporation did not own any of the Company's outstanding common stock.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated:
		For the Year Ended December 31,
		2014			2013			2012
		(in thousands)
	United States	$	50,953		$	51,276		$	(152,322	)
	Foreign	—			(1,934		)	(1,469		)
	Total income (loss) before income taxes	$	50,953		$	49,342		$	(153,791	)
	The Company did not report any current provision for income taxes for the years ended December 31, 2014, 2013 and 2012. The Company’s deferred income tax expense (benefit) consists of the following for the periods presented:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Deferred:
	Federal	$	—		$	(15,299	)	$	—
	State	—			(743		)	—
	Foreign	—			—			—
	Income tax expense (benefit)	$	—		$	(16,042	)	$	—
	The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Expected income tax provision (benefit) at statutory rate	$	17,833		$	11,655		$	(53,827	)
	State tax, tax effected	803			96			(2,562		)
	Stock-based compensation expense	(1,291		)	605			560
	Tax effect of Canadian tax rate differences	—			193			(125		)
	Loss of Canadian tax attributes due to migration from Canada	—			19,825			—
	Gain on acquisition of assets at fair value	—			(9,685		)	—
	Non-deductible costs of migration from Canada to U.S.	—			95			—
	Other	38			(49		)	15
	Other changes in valuation allowance	(17,383		)	(38,777		)	55,939
	Actual income tax provision	$	—		$	(16,042	)	$	—
	The components of the Company’s U.S. deferred taxes are as follows:
		As of December 31,
		2014			2013
		(in thousands)
	Deferred tax asset (liability):
	Capital assets	$	(134,223	)	$	(77,456	)
	Stock-based compensation	4,504			6,501
	Net operating loss carry forwards	164,056			122,675
	Foreign tax credit carry forwards	50,681			50,681
	Valuation allowance	(85,018		)	(102,401		)
	Net deferred tax asset	$	—		$	—
	The Company has approximately $447.0 million of net operating loss carry forwards as of December 31, 2014, which, if not utilized, will expire between 2030 and 2034. For U.S. federal income tax purposes, as of December 31, 2014, the Company has foreign tax credit carry forwards of $50.7 million, which, if not utilized, will expire in 2019. The utilization of the net operating loss carry forward and the foreign tax credit carry forward are dependent on the Company generating future taxable income and U.S. tax liability, as well as other factors.
	Effective November 14, 2013, the Company withdrew from Canada and re-incorporated in Delaware (the “Migration”). As a result of the Migration, the Company's Canadian tax attributes have effectively been forfeited. As all of the Canadian tax attributes were subject to a valuation allowance, the Migration from Canada to the U.S. is not expected to result in any Canadian tax expense. Current authoritative guidance requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2014, the Company did not have any material unrecognized tax benefits that, if recognized, would affect the effective tax rate.
	The Company is subject to examination of income tax filings in the U.S. and various state jurisdictions for the periods 2010 and forward and the foreign jurisdictions of Canada and Australia for the tax periods 2000 and forward due to the Company’s continued loss position in such jurisdictions.
	Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Share	Earnings per Share
	In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.
		For the Years Ended December 31,
		2014		2013		2012
		(in thousands, except per share and share data)
	Net income (loss) attributable to common stockholders	$	36,529	$	39,964	$	(160,868	)
	Weighted average shares of common stock outstanding - basic	63,270,733		60,220,115		63,538,362
	Incremental shares from unvested restricted shares	2,451,903		2,869,490		—
	Incremental shares from outstanding stock options	97,491		26,095		—
	Incremental shares from outstanding PBUs	672,462		502,701		—
	Weighted average shares of common stock outstanding - diluted	66,492,589		63,618,401		63,538,362
	Net income (loss) per share of common stock attributable to common stockholders:
	Basic	$	0.58	$	0.66	$	(2.53	)
	Diluted	$	0.55	$	0.63	$	(2.53	)
	Shares of common stock excluded from denominator as anti-dilutive:
	Unvested restricted shares	34,058		3,505		1,831,435
	Stock options	—		—		936,967
	Total	34,058		3,505		2,768,402

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	Commitments and Contingencies
	Contractual Obligations
	The Company leases its office facilities and certain office equipment under non-cancelable operating lease agreements terminating in October 2018. For the years ended December 31, 2014, 2013 and 2012, office lease expense totaled approximately $649,000, $372,000 and $377,000, respectively.
	As of December 31, 2014, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows:
	2015	$	640
	2016	498
	2017	187
	2018	161
		$	1,486
	Litigation
	Chesapeake Exploration L.L.C. (“Chesapeake Exploration”) and Chesapeake Energy Corp.  (“Chesapeake Energy”) v. Gastar Exploration Ltd., Gastar Exploration Texas, LP, and Gastar Exploration Texas, LLC (No. 4:12-cv-2922), United States District Court for the Southern District of Texas, Houston Division.  This lawsuit, filed on October 1, 2012, was resolved as part of an acquisition transaction which closed on June 7, 2013. Thereafter, the parties to the Chesapeake lawsuit filed stipulation of dismissal of prejudice, and on June 11, 2013, the court entered an order dismissing the case with prejudice. In connection with the resolution of the matter, the Company made an aggregate cash payment of approximately $80.0 million, comprised of approximately $69.4 million in property acquisition costs (subject to adjustment for an acquisition effective date of October 1, 2012), stock repurchase price of approximately $9.8 million and an additional $1.0 million for litigation settlement.
	Gastar Exploration USA, Inc., et al v. Williams Ohio Valley Midstream LLC (American Arbitration Association Matter No. 70-198-Y-00461-13). On July 16, 2013, Gastar USA and two similarly situated co-claimants initiated an arbitration proceeding against Williams Ohio Valley Midstream LLC (“Williams OVM”). The claimants allege that Williams OVM has breached various agreements relating to the gathering, processing and marketing of natural gas, NGLs and condensate produced from properties that are owned in part by Gastar USA in the Marcellus Shale in Marshall and Wetzel Counties, West Virginia, and requested that an Arbitration Panel assess an unspecified amount of damages against Williams OVM for, among other claims, failure to timely construct certain gathering and processing facilities and maximize the net value of the condensate and NGLs produced as provided in the agreements. On August 7, 2013, Williams OVM filed an answering statement and counterclaim for damages in excess of $612,000 in the arbitration matter. On December 31, 2013, the parties informed the Arbitration Panel that they had reached an agreement in principle to settle their disputes. The disputes were subsequently settled, on a confidential basis, between both parties on June 17, 2014. Although there were some changes to the contracts, there were no changes to existing contractual fees. After production taxes and lease operating expense reimbursement benefit, the net arbitration settlement amount received by Gastar USA was approximately $8.6 million.
	Gastar Exploration Ltd vs U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No. 2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage are $20.0 million. The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012. The Company appealed the District Court ruling and on July 15, 2013, the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The insurers filed a motion for reconsideration in the Court of Appeals, which that court denied. The insurers sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The case will be remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of whether the Company's claims are securities claims covered by the insuring agreements.
	Eagle Natrium LLC v. Gastar Exploration USA, Inc., Cause No. GD-14-7208, In the Court of Common Pleas of Allegheny County, Pennsylvania. On April 22, 2014, Eagle Natrium LLC (“Eagle”), a wholly-owned subsidiary of Axiall Corporation, filed a complaint against Gastar in the Court of Common Pleas of Allegheny County, Pennsylvania seeking to enjoin Gastar's hydraulic fracturing and completion operations on three wells drilled from Gastar's Goudy pad in Marshall County, West Virginia, or conducting any activity that poses a substantial risk of harm to Eagle's brine operations. Gastar is the operator of approximately 13,700 acres in Marshall County, West Virginia, including a 3,300 gross acre oil and gas lease adjacent to Eagle's facilities. Eagle operates a subsurface brine operation which it acquired from the lessor of Gastar's lease. Eagle has asserted its right to relief based on certain of the lessor's rights which were assigned to Eagle by the lessor solely as they relate to the brine and related facilities. The complaint alleges that the contemplated operations of Gastar, which include hydraulic fracturing, pose a danger to the subsurface brine operations of Eagle. All wells drilled to date on this lease, including the wells principally involved in the complaint, were previously approved pursuant to the terms of Gastar's lease. Proved undeveloped well locations on this lease accounted for 87.7 Bcfe, or 19%, of the Gastar's total company proved reserves at June 30, 2014. A hearing on the request for preliminary injunction was held over the course of two weeks. After considering the evidence presented at the hearing and the party's briefing, the court issued an order on October 21, 2014 denying the request for a preliminary injunction. On October 30, 2014, Eagle filed a nearly identical lawsuit against Gastar and the West Virginia Department of Environmental Protection (“WVDEP”) in the Circuit Court of Marshall County, West Virginia, requesting a temporary restraining order prohibiting Gastar from hydraulically fracturing the same wells that were the subject of the proceeding in Pennsylvania. That same day, the Court held a hearing and granted a temporary restraining order against Gastar and required that Eagle post an $800,000 bond. On December 24, 2014, Circuit Judge David W. Hummel dismissed Gastar from the lawsuit finding that Eagle was collaterally and judicially estopped from maintaining in West Virginia a lawsuit that was essentially identical to the prior lawsuit in Pennsylvania. After further briefing, Judge Hummel dismissed the claims against the WVDEP on December 29, 2014.
	After the dismissal of the West Virginia lawsuit, Gastar began completion operations and has since completed the three wells drilled from its Goudy pad that formed the basis of Eagle’s complaint.  Gastar now plans to move to dismiss the suit in Pennsylvania on account of mootness. Gastar is currently seeking attorney’s fees and damages in West Virginia and also plans to seek attorney’s fees and damages in Pennsylvania pending disposition of the matter.
	The Company has been expensing legal defense costs on these proceedings as they are incurred.
	The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
	Commitments
	During December 2010, we, along with Atinum, entered into a gas purchase agreement with SEI Energy, LLC (“SEI”) with respect to our Marshall County, West Virginia production. The initial term of the gas purchase agreement is five years with the option to extend the term of the gas purchase agreement for an additional five year period. Our Marshall County, West Virginia production is dedicated to SEI for the term of the gas purchase agreement. During June 2014, the Company entered into an agreement to include the dedication of all of our Wetzel County, West Virginia production to SEI in addition to our Marshall County, West Virginia production. SEI will purchase all hydrocarbon production, including all natural gas, condensate and natural gas liquids. SEI has an agreement to utilize the Williams Ohio Valley Midstream LLC (“Williams") midstream facilities (formerly owned by Caiman Energy Midstream, LLC), including its 520.0 MMcf/d Fort Beeler processing plant or William's 200.0 MMcf/d Oak Grove processing plant located in Marshall County, West Virginia for transporting and processing. In order to secure access to the Williams facilities, we, Atinum and SEI dedicated all hydrocarbons purchased and produced in Marshall County, West Virginia for a term of ten years.
	Restoration, Removal and Environmental Liabilities
	The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year. At December 31, 2014, the Company had total liabilities of $5.6 million related to asset retirement obligations of which $82,000 is recorded as short-term liabilities and $5.5 million is recorded as long-term liabilities. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 5, “Asset Retirement Obligation.”
	Indemnifications
	Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if any, is difficult to predict.
	Employment Agreements
	The Company entered into employment agreements with its Chief Executive Officer and its Chief Financial Officer, effective February 24, 2005 (as amended July 25, 2008 and February 3, 2011) and May 17, 2005 (as amended July 25, 2008 and April 10, 2012), respectively. The Company entered into an employment agreement with its Chief Operating Officer on June 19, 2014. The agreements set forth, among other things, annual compensation, and adjustments thereto, bonus payments, fringe benefits, termination and severance provisions.
	The Company also has entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to indemnify them to the fullest extent permitted by law against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to the beneficiary of such indemnification agreements.

Concentration_of_Risk_and_Sign

Concentration of Risk and Significant Customers	12 Months Ended
	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Concentration of Risk and Significant Customers	Concentration of Risk and Significant Customers
	The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated:
			For the Years Ended December 31,
			2014		2013		2012
	Appalachian Basin		39	%	65	%	72	%
	Mid-Continent		61	%	26	%	—	%
	Hilltop Area, East Texas(1)		—	%	9	%	27	%
	Powder River Basin(2)		—	%	—	%	1	%
	_______________________________
	-1	The Company's working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013.
	-2	The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012.
	The following table provides information regarding our significant customers and the percentages of oil, condensate, natural gas and NGLs revenues, excluding hedge impact, which they represented for the periods indicated:
			For the Years Ended December 31,
			2014		2013		2012
	SEI		50	%	56	%	47	%
	Sunoco		37	%	16	%	—	%
	Clearfield Appalachian		—	%	8	%	14	%
	ETC		—	%	8	%	24	%
	SEI purchases the majority of the Company's Appalachian Basin production. There are limited oil, condensate, natural gas and NGLs purchase and transportation alternatives currently available in Appalachia. If SEI was to cease purchasing and transporting the Company’s Appalachian Basin oil, condensate, natural gas and NGLs production and the Company was unable to obtain timely access to existing or future facilities on acceptable terms, or in the event of any significant change affecting these facilities, including delays in the commencement of operations of any new pipelines or the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise, the Company’s ability to conduct normal operations would be restricted. SEI and Sunoco purchase the majority of the Company's Mid-Continent production. There are numerous purchase and transportation alternatives currently available in the Mid-Continent so in the event that SEI or Sunoco were to cease purchasing and transporting our oil, condensate, natural gas and NGLS production, the Company's ability to conduct normal operations would not be significantly restricted. Prior to the Company's sale of its interest in East Texas, ETC treated, transported and purchased substantially all of the Company’s East Texas natural gas production.

Statement_Of_Cash_Flows_Supple

Statement Of Cash Flows - Supplemental Information	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Statement Of Cash Flows - Supplemental Information	Statement of Cash Flows – Supplemental Information
	The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	24,632		$	7,341		$	39
	Non-cash transactions:
	Capital expenditures included in accounts payable and accrued drilling costs	$	12,777		$	582		$	4,666
	Capital expenditures included in accounts receivable	4,077			(4,077		)	(929		)
	Asset retirement obligation included in oil and natural gas properties	221			(1,302		)	1,164
	Asset retirement obligation sold/assigned to operator	(645		)	(4,354		)	(2,227		)
	Application of advances to operators	58,326			19,755			7,441
	Other	(11		)	47			(36		)

Quarterly_Consolidated_Financi

Quarterly Consolidated Financial Data - Unaudited	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Consolidated Financial Data - Unaudited	Quarterly Consolidated Financial Data – Unaudited
	The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2014 and 2013:
		2014
		First			Second		Third			Fourth
		Quarter			Quarter		Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	32,327		$	35,897	$	41,746		$	61,448
	Income from operations	8,497			12,539		20,413			37,063
	Income before provision for income taxes	1,611			5,627		13,425			30,290
	Net income	1,611			5,627		13,425			30,290
	Dividend on preferred stock	3,576			3,611		3,618			3,619
	Net (loss) income attributable to common stockholders	(1,965		)	2,016		9,807			26,671
	Net (loss) income per share of common stock attributable to common stockholders:
	Basic	$	(0.03	)	$	0.03	$	0.16		$	0.35
	Diluted	$	(0.03	)	$	0.03	$	0.15		$	0.34
	Weighted average shares of common stock outstanding:
	Basic	58,204,532			58,702,982		60,006,903			75,994,979
	Diluted	58,204,532			61,922,874		63,399,446			78,577,762
		2013
		First			Second		Third			Fourth
		Quarter			Quarter		Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	11,264		$	30,926	$	18,840		$	26,725
	(Loss) income from operations	(1,849		)	13,809		1,626			5,178
	(Loss) income before provision for income taxes(1)	(2,456		)	53,970		(1,808		)	(16,406		)
	Net (loss) income	(2,456		)	53,970		(1,808		)	(364		)
	Dividend on preferred stock	2,130			2,134		2,134			2,980
	Net (loss) income attributable to common stockholders	(4,586		)	51,836		(3,942		)	(3,344		)
	Net (loss) income per share of common stock attributable to common stockholders:
	Basic	$	(0.07	)	$	0.83	$	(0.07	)	$	(0.06	)
	Diluted	$	(0.07	)	$	0.81	$	(0.07	)	$	(0.06	)
	Weighted average shares of common stock outstanding:
	Basic	63,864,527			62,398,472		57,359,357			57,433,550
	Diluted	63,864,527			63,813,423		57,359,357			57,433,550
	_________________________________
	-1	Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.

Supplemental_Oil_and_Gas_Discl

Supplemental Oil and Gas Disclosures - Unaudited	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Supplemental Oil and Disclosures - Unaudited	Supplemental Oil and Gas Disclosures – Unaudited
	Capitalized Costs Relating Oil and Producing Activities
	The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities for the periods indicated:
		As of December 31,
		2014				2013				2012
		(in thousands)
	Proved properties:
	United States	$	1,124,367			$	935,773			$	671,193
	Total proved properties	1,124,367				935,773				671,193
	Unproved properties:
	United States	128,274				96,220				67,892
	Total unproved properties	128,274				96,220				67,892
	Total oil and natural gas properties	1,252,641				1,031,993				739,085
	Less:
	Impairment of proved oil and natural gas properties
	United States	(337,939		)		(337,939		)		(337,939		)
	Accumulated depreciation, depletion and amortization	(223,555		)		(177,790		)		(145,631		)
	Net capitalized costs	$	691,147			$	516,264			$	255,515
	Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs of approximately $2.4 million, $3.4 million and $4.8 million at December 31, 2014, 2013 and 2012, respectively.
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
	The following table sets forth costs incurred related to the Company’s oil and natural gas activities in the U.S. for the periods indicated:
			For the years ended December 31,
			2014				2013				2012
			(in thousands)
	Property acquisition
	Proved(1)		$	—			$	189,594			$	—
	Unproved(2)		41,475				71,472				25,676
	Exploration		127,384				36,893				10,041
	Development		57,913				53,058				111,878
	Total costs incurred		$	226,772			$	351,017			$	147,595
	_________________________________
	-1	The 2013 property acquisition costs exclude a downward adjustment of $2.6 million for fair value of acquisition.
	-2	The 2013 property acquisition costs exclude $46.3 million of adjustment for fair value of acquisition.
	Results of Operations for Oil and Natural Gas Producing Activities
	The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated:
		For the Year Ended December 31,
		2014				2013				2012
		(in thousands, except per Mcfe data)
	Oil, condensate, natural gas and NGLs sales, including commodity derivatives	$	171,418			$	87,755			$	49,940
	Production expenses	(29,735		)		(18,113		)		(13,408		)
	Impairment of oil and natural gas properties	—				—				(150,787		)
	Depreciation, depletion and amortization	(45,765		)		(32,158		)		(25,195		)
	Results of producing activities	$	95,918			$	37,484			$	(139,450	)
	Depreciation, depletion and amortization per MBoe	$	12.34			$	9.94			$	11.41
	The results of producing activities exclude interest charges and general corporate expenses and represent U.S. activities only.
	In accordance with current authoritative guidance, estimates of the Company’s proved reserves and future net revenues are made using benchmark prices, before lease adjustments, that are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2014 and 2013. The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves:
		As of December 31,
		2014				2013
	Natural gas (per MMBtu):
	Henry Hub	$	4.35			$	3.67
	Oil (per Bbl):
	WTI spot	$	94.99			96.78
	These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas prices and oil prices, which have fluctuated significantly in recent years.
	Net Proved and Proved Developed Reserve Summary
	Reserve Estimation. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2014, 2013, and 2012 and includes reserve information for the Appalachian Basin as of December 31, 2014, 2013, and 2012, reserve information for the Mid-Continent as of December 31, 2014 and reserve information for the Hilltop Area of East Texas as of 2012. The Company sold its working interest in the Hilltop Area of East Texas on October 2, 2013, with an effective date of January 1, 2013. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e., prices and costs as of the date the estimate is made). Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. The Company’s proved developed and proved undeveloped reserves are located only in the U.S.
	The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2014, 2013 and 2012:
	Change in Proved Reserves	Natural  Gas			NGLs			Condensate and Oil			MBoe (3) Equivalents (4)
		(MMcf) (1)			(MBbl) (2)			(MBbl) (2)
	Proved reserves as of December 31, 2011	91,652			2,757			1,921			19,953
	2012 Activity:
	Extensions and discoveries(5)	57,835			2,783			2,439			14,861
	Revisions of previous estimates	(6,518	)		(348	)		(796	)		(2,230	)
	Production	(10,564	)		(270	)		(177	)		(2,208	)
	Purchases in place	—			—			7			7
Sales in place	(1,395	)		—			—			(231	)
Proved reserves as of December 31, 2012	131,010			4,922			3,394			30,152
2013 Activity:
Extensions and discoveries(6)	52,750			2,306			4,385			15,483
Revisions of previous estimates	8,114			714			(337	)		1,729
Production	(13,366	)		(494	)		(515	)		(3,237	)
Purchases in place	26,961			2,350			7,796			14,639
Sales in place	(24,759	)		—			(5	)		(4,132	)
Proved reserves as of December 31, 2013	180,710			9,798			14,718			54,634
2014 Activity:
Extensions and discoveries(7)	121,672			9,394			13,137			42,810
Revisions of previous estimates	(2,465	)		7,205			1,780			8,574
Production	(11,598	)		(800	)		(975	)		(3,708	)
Sales in place	(1,314	)		(4	)		(24	)		(247	)
Proved reserves as of December 31, 2014	287,005			25,593			28,636			102,063
_________________________________
(1)Million cubic feet or million cubic feet equivalent, as applicable
-2	Thousand barrels
-3	Thousand barrels of oil, condensate or NGLs equivalent.
-4	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
-5	The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery.
-6	Of the 2013 extensions and discoveries, 74% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
-7	Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
Proved Developed and Undeveloped Reserves	Natural Gas			NGLs			Condensate and Oil			MBoe (3) Equivalents (4)
	(MMcf) (1)			(MBbl) (2)			(MBbl) (2)
31-Dec-12
Proved developed reserves	95,602			3,215.80			1,959			21,109
Proved undeveloped reserves	35,408			1,706			1,435			9,042
Total	131,010			4,922			3,394			30,151
31-Dec-13
Proved developed reserves	114,195			6,025			5,834			30,892
Proved undeveloped reserves	66,515			3,773			8,884			23,742
Total	180,710			9,798			14,718			54,634
31-Dec-14
Proved developed reserves	114,564			10,726			6,968			36,789
Proved undeveloped reserves	172,441			14,867			21,668			65,274
Total	287,005			25,593			28,636			102,063
_________________________________
(1)Million cubic feet or million cubic feet equivalent, as applicable
-2	Thousand barrels
-3	Thousand barrels of oil, condensate or NGLs equivalent.
-4	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented.
For the years ended December 31, 2014, 2013 and 2012 future cash inflows were computed using the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil (the “benchmark base prices”). For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations:
	For the Years Ended December 31,
	2014				2013				2012
Natural gas, per MMBtu
Henry Hub	$	4.35			$	3.67			$	2.76
Oil, per barrel:
WTI spot	$	94.99			$	96.78			$	94.71
These benchmark base prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. The Company also includes its standard overhead charges pursuant to the respective property joint operating agreements in the calculation of its future cash flows.
The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate could also result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or changes in regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is presented below:
	United States
	(in thousands)
December 31, 2012:
Future cash inflows	$	672,142
Future production costs	(167,864		)
Future development costs	(83,697		)
Future income taxes(1)	—
Future net cash flows	420,581
10% annual discount for estimated timing of cash flows	(213,772		)
Standardized measure of discounted future cash flows	$	206,809
December 31, 2013:
Future cash inflows	$	2,103,023
Future production costs	(588,568		)
Future development costs	(296,666		)
Future income taxes	(215,502		)
Future net cash flows	1,002,287
10% annual discount for estimated timing of cash flows	(486,458		)
Standardized measure of discounted future cash flows	$	515,829
December 31, 2014:
Future cash inflows	$	3,855,227
Future production costs	(1,048,554		)
Future development costs	(611,602		)
Future income taxes	(486,593		)
Future net cash flows	1,708,478
10% annual discount for estimated timing of cash flows	(891,739		)
Standardized measure of discounted future cash flows	$	816,739
_________________________________
-1	No future taxes payable has been included in the determination of discounted future net cash flows for 2012 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The principal sources of changes in the standardized measure of future net cash flows are as follows:
	United States
	(in thousands)
December 31, 2011	$	212,783
Extensions and discoveries, less related costs	112,390
Sale of natural gas and oil, net of production costs	(29,110		)
Purchases of reserves in place	64
Sales of reserves in place	(216		)
Revisions of previous quantity estimates	(30,959		)
Net change in income tax	4,334
Net change in prices and production costs	(98,589		)
Accretion of discount	1,152
Development costs incurred	19,702
Net change in estimated future development costs	2,518
Change in production rates (timing) and other	12,740
31-Dec-12	$	206,809
Extensions and discoveries, less related costs	196,448
Sale of natural gas and oil, net of production costs	(74,394		)
Purchases of reserves in place	247,208
Sales of reserves in place	(9,063		)
Revisions of previous quantity estimates	6,191
Net change in income tax	(76,701		)
Net change in prices and production costs	79,820
Accretion of discount	1,211
Development costs incurred	23,567
Net change in estimated future development costs	(97,461		)
Change in production rates (timing) and other	12,194
31-Dec-13	$	515,829
Extensions and discoveries, less related costs	369,806
Sale of natural gas and oil, net of production costs	(122,114		)
Sales of reserves in place	(1,475		)
Revisions of previous quantity estimates	101,044
Net change in income tax	(95,245		)
Net change in prices and production costs	59,786
Accretion of discount	(3,996		)
Development costs incurred	37,461
Net change in estimated future development costs	(1,277		)
Change in production rates (timing) and other	(43,081		)
31-Dec-14	$	816,739

Recovered_Sheet1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation
	The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with U.S. GAAP. The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 18. “Supplemental Oil and Gas Disclosures.”
	All prior year balances are those of Gastar Exploration, Inc.
Reclassifications	Reclassifications
	Certain reclassifications of prior year balances have been made to conform to current year presentation; these reclassifications have no impact on net income (loss).
Subsequent Events	Subsequent Events
	In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate.
Principles of Consolidation	Principles of Consolidation
	The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation.
Use of estimates in Preparation of Financial Statements	Use of estimates in Preparation of Financial Statements
	The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties.
Cash and Cash Equivalents	Cash and Cash Equivalents
	The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $11.0 million and $32.4 million as of December 31, 2014 and 2013, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.
Accounts Receivable	Accounts Receivable
	Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible.
Oil and Natural Gas Properties	Oil and Natural Gas Properties
	The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center.
	Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.
	Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations.
	In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.
	The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2014 and 2013 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price.
	Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered.
	The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted.
Asset Retirement Obligation	Asset Retirement Obligation
	Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations.
Furniture and Equipment	Furniture and Equipment
	Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years.
Capitalized Interest	Capitalized Interest
	The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The Notes and Revolving Credit Facility were included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2014. Currently, the Company only capitalizes interest on the Notes. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets.
Fair Value of Financial Instruments	Fair Value of Financial Instruments
	The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value.
Deferred Financing Costs	Deferred Financing Costs
	Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense.
Derivative Instruments and Hedging Activity	Derivative Instruments and Hedging Activity
	The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.”
	The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in (loss) gain on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in (loss) gain on commodity derivatives contracts in the Company’s consolidated statement of operations.
Stock-Based Compensation	Stock-Based Compensation
	The Company reports compensation expense for restricted common stock, performance based units (“PBUs”) and stock options granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.
	Stock-based compensation cost for restricted shares is estimated at the grant date based on the award's fair value, which is equal to the prior day's closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant based on the award's fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. The Company records stock-based compensation costs for stock options granted based on the grant-date fair value as calculated using the Black-Scholes-Merton option-pricing model. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, forfeiture rates and expected option life. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense for future grants may differ materially from that recorded in the current period. The Company did not award any stock option grants during 2014, 2013 or 2012.
Treasury Stock	Treasury Stock
	Treasury stock purchases are recorded at cost as a reduction to common stock. Shares of common stock are canceled upon repurchase.
Revenue Recognition	Revenue Recognition
	The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company's NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company's wet gas production. The Company's reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which the Company is credited under its sales contracts. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2014 and 2013.
	The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, oil, condensate, natural gas and NGLs volumes sold are not significantly different from the Company’s share of production.
	The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet.
Deferred Income Taxes	Deferred Income Taxes
	Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.
Comprehensive Income	Comprehensive Income
	Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Company has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.
Earnings or Loss per Share	Earnings or Loss per Share
	Basic earnings or loss per share is computed on the basis of the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed based upon the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of stock options, unvested restricted shares and PBUs.
Joint Venture Operations	Joint Venture Operations
	The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Industry Segment and Geographic Information	Industry Segment and Geographic Information
	The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.
Foreign Currency Exchange	Foreign Currency Exchange
	The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the Company is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction.
	All of the Company’s operations are conducted in U.S. dollars. The Company owns immaterial non-operating working interests in two natural gas wells located in Alberta, Canada, from which it has received no revenue since January 1, 2012.
	Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations.
Recent Accounting Developments	Recent Accounting Developments
	The following recently issued accounting pronouncements have been adopted or may impact us in future periods:
	Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.
	Income taxes. In July 2013, the FASB issued an amendment to previously issued guidance regarding the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The amendment requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except as follows. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and should be made presuming disallowance of the tax position at the reporting date. This amendment does not require new recurring disclosures. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this guidance did not impact the Company's operating results, financial position or cash flows.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of the activity related to the allowance for doubtful accounts	A summary of the activity related to the allowance for doubtful accounts is as follows:
		For the years ended December 31,
		2014			2013			2012
		(in thousands)
	Allowance for doubtful accounts, beginning of year	$	507		$	546		$	551
	Expense	—			—			—
	Reductions/write-offs	(507		)	(39		)	(5		)
	Allowance for doubtful accounts, end of year	$	—		$	507		$	546
Schedule of deferred charges and accumulated amortization	The following table indicates deferred charges and related accumulated amortization as of the dates indicated:
		As of December 31,
		2014			2013
	Deferred charges	$	3,664		$	3,269
	Accumulated amortization	(1,078		)	(319		)
	Deferred charges, net	$	2,586		$	2,950

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Business Acquisition [Line Items]
Property, Plant and Equipment	The Company's total property, plant and equipment consists of the following:
		December 31,
		2014				2013
		(in thousands)
	Oil and natural gas properties, full cost method of accounting:
	Unproved properties	$	128,274			$	96,220
	Proved properties	1,124,367				935,773
	Total oil and natural gas properties	1,252,641				1,031,993
	Furniture and equipment	3,010				2,691
	Total property and equipment	1,255,651				1,034,684
	Impairment of proved natural gas and oil properties	(337,939		)		(337,939		)
	Accumulated depreciation, depletion and amortization	(225,412		)		(179,232		)
	Total accumulated depreciation, depletion and amortization	(563,351		)		(517,171		)
	Total property and equipment, net	$	692,300			$	517,513
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:
		December 31,
		2014				2013
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	29,193			$	4,774
	Acreage acquisition costs	91,362				86,097
	Capitalized interest	7,719				5,349
	Total unproved properties excluded from amortization	$	128,274			$	96,220
Schedule of Relevant Assumptions Used in Ceiling Test Computations	The table below sets forth relevant assumptions utilized in the quarterly ceiling test computations for the respective periods noted:
			2014
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)						$	4.35		$	4.24	$	4.1	$	3.99
	West Texas Intermediate oil price (per Bbl)(1)						$	94.99		$	99.08	$	100.11	$	98.3
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
			2013
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)						$	3.67		$	3.61	$	3.44	$	2.95
	West Texas Intermediate oil price (per Bbl)(1)						$	96.78		$	91.69	$	88.13	$	89.17
	Impairment recorded (pre-tax) (in thousands)		$	—			$	—		$	—	$	—	$	—
			2012
			Total Impairment				31-Dec			30-Sep		30-Jun		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)						$	2.76		$	2.83	$	3.15	$	3.73
	West Texas Intermediate oil price (per Bbl)(1)						$	91.21		$	91.48	$	92.17	$	94.65
	Impairment recorded (pre-tax) (in thousands)		$	150,787			$	—		$	78,054	$	72,733	$	—
	_________________________________
	-1	For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.
Chesapeake Assets
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Chesapeake acquisition (in thousands):
	Consideration:
	Cash consideration		$	69,371
	Fair Value of Liabilities Assumed:
	Deferred tax liability		16,042
	Total purchase price plus liabilities assumed		$	85,413
	Estimated Fair Value of Assets Acquired:
	Unproved properties		$	86,327
	Proved properties		26,756
	Total assets acquired		$	113,083
	Bargain purchase gain		$	27,670
WEHLU Purchase Agreement
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the estimated fair value of the assets acquired in connection with the WEHLU Acquisition (in thousands):
	Consideration:
	Cash consideration		$	177,778
	Estimated Fair Value of Assets Acquired:
	Unproved properties		$	13,026
	Proved properties		164,752
	Total assets acquired		$	177,778
Business Acquisition, Pro Forma Information	The amounts of revenues and revenues in excess of direct operating expenses included in the Company's consolidated statements of operations for the Chesapeake and WEHLU Acquisitions are shown in the table below. Direct operating expenses includes lease operating expenses and production taxes.
			Year Ended December 31, 2013
			(in thousands)
	Revenues		$	11,292
	Excess of revenues over direct operating expenses		$	7,591
	The following unaudited pro forma results for the years ended December 31, 2013 and 2012 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of each respective period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.
			For the Years Ended December 31,
			2013				2012
			(in thousands, except per share data)
			(Unaudited)
	Revenues		$	132,721			$	97,760
	Net Loss		$	(4,836	)		$	(175,809	)
	Loss per share:
	Basic		$	(0.08	)		$	(2.77	)
	Diluted		$	(0.08	)		$	(2.77	)

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	A summary of the activity related to the asset retirement obligation is as follows:
		For the years ended December 31,
		2014			2013			2012
		(in thousands)
	Asset retirement obligation, beginning of year	$	6,063		$	6,963		$	8,275
	Liabilities incurred during period	305			3,416			271
	Liabilities settled during period	(704		)	(126		)	(297		)
	Accretion expense	506			468			388
	Revision in previous estimates and other	32			60			553
	Deletions related to property disposals	(645		)	(4,718		)	(2,227		)
	Asset retirement obligation, end of year	$	5,557		$	6,063		$	6,963

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring and Nonrecurring	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013:
		Fair value as of December 31, 2014
		Level 1		Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	11,008	$	—		$	—		$	11,008
	Commodity derivative contracts	—		—			27,502			27,502
	Liabilities:
	Commodity derivative contracts	—		—			—			—
	Total	$	11,008	$	—		$	27,502		$	38,510
		Fair value as of December 31, 2013
		Level 1		Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	32,393	$	—		$	—		$	32,393
	Restricted cash	—		—			—			—
	Commodity derivative contracts	—		—			7,545			7,545
	Liabilities:
	Commodity derivative contracts	—		—			(3,781		)	(3,781		)
	Total	$	32,393	$	—		$	3,764		$	36,157
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2014 and 2013. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2014 and 2013.
		For the years ended December 31,
		2014		2013
		(in thousands)
	Balance at beginning of period	$	3,764	$	6,465
	Total gains (losses)
	included in earnings	19,569		(4,752		)
	Purchases	369		9,772
	Issuances	—		(2,308		)
	Settlements(1)	3,800		(5,413		)
	Balance at end of period	$	27,502	$	3,764
	The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2014 and 2013	$	23,902	$	(9,967	)
	_________________________________
	-1	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations.

Derivative_Instruments_And_Hed1

Derivative Instruments And Hedging Activity (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative [Line Items]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location	The following table provides information regarding the deferred put premium liabilities for the periods indicated:
		For the Years Ended December 31,
		2014				2013
		(in thousands)
	Current commodity derivative premium put payable	$	2,481			$	145
	Long-term commodity derivative premium payable	4,702				7,000
	Total unamortized put premium liabilities	$	7,183			$	7,145
Schedule of Deferred Put Premium Liability
		For the Year December 31, 2014
		(in thousands)
	Put premium liabilities, beginning balance	$	7,145
	Less:
	Amortization of put premium liabilities	(145		)
	Additional put premium liabilities	183
	Put premium liabilities, ending balance	$	7,183
Schedule of Future Amortization of Deferred Put Premium Liabilities	The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2014:
		Amortization
		(in thousands)
	January to December 2015	$	2,481
	January to December 2016	2,408
	January to December 2017	1,460
	January to August 2018	834
	Total unamortized put premium liabilities	$	7,183
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments:
		Fair Values of Derivative Instruments
		Derivative Assets (Liabilities)
				Fair Value
				December 31,
		Balance Sheet Location		2014				2013
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	Current assets		$	19,687			$	—
	Commodity derivative contracts	Other assets		7,815				7,545
	Commodity derivative contracts	Current liabilities		—				(3,403		)
	Commodity derivative contracts	Long-term liabilities		—				(378		)
	Total derivatives not designated as hedging instruments			$	27,502			$	3,764
				Amount of Gain (Loss)
				Recognized in Income on
				Derivatives For the Years Ended December 31,
		Location of Gain (Loss) Recognized in		2014				2013				2012
		Income on Derivatives
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	Gain (loss) on commodity derivatives contracts		$	19,569			$	(4,752	)		$	7,422
	Commodity derivative contracts	Interest expense		—				—				(186		)
	Total			$	19,569			$	(4,752	)		$	7,236
Natural Gas
Derivative [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of December 31, 2014, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume			Volume			Price
					(in MMBtu's)
	2015(1)		Protective spread		10,000			900,000			$	4.46			$	—	$	3.7	$	—
	2015(1)		Call spread		10,000			900,000			$	—			$	—	$	—	$	5
	2015		Fixed price swap		400			146,000			$	4			$	—	$	—	$	—
	2015		Fixed price swap		2,500			912,500			$	4.06			$	—	$	—	$	—
	2015		Protective spread		2,600			949,000			$	4			$	—	$	3.25	$	—
	2015(1)		Producer three-way collar		3,750			337,500			$	—			$	4.6	$	3.5	$	5.34
	2015(1)		Producer three-way collar		2,500			337,500			$	—			$	4.4	$	3.65	$	5
	2015		Producer three-way collar		2,000			760,000			$	—			$	4	$	3.25	$	4.58
	2015		Basis swap(2)		2,500			912,500			$	(1.12	)		$	—	$	—	$	—
	2015		Basis swap(2)		2,500			912,500			$	(1.11	)		$	—	$	—	$	—
	2015		Basis swap(2)		2,500			912,500			$	(1.14	)		$	—	$	—	$	—
	2015(3)		Protective spread		5,000			1,375,000			$	4			$	—	$	3.25	$	—
	2015(3)		Producer three-way collar		2,500			687,500			$	—			$	3.7	$	3	$	4.09
	2015(3)		Producer three-way collar		5,000			1,375,000			$	—			$	3.77	$	3	$	4.11
	2016		Protective spread		2,000			732,000			$	4.11			$	—	$	3.25	$	—
	_______________________________
	-1	For the period January to March 2015.
	-2	Represents basis swaps at the sales point of Dominion South.
	-3	For the period April to December 2015.
Crude Oil
Derivative [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of December 31, 2014, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base				Floor		Short		Ceiling
					Daily			Notional			Fixed				(Long)		Put		(Short)
					Volume (1)			Volume			Price
					(in Bbls)
	2015(2)		Costless collar		400			72,400			$	—			$	85	$	—	$	96.5
	2015(2)		Costless collar		366			66,300			$	—			$	85	$	—	$	97.8
	2015(2)		Costless collar		150			27,150			$	—			$	85	$	—	$	96.25
	2015(3)		Costless three-way collar		400			73,600			$	—			$	85	$	70	$	96.5
	2015(3)		Costless three-way collar		325			59,800			$	—			$	85	$	65	$	97.8
	2015(3)		Costless three-way collar		50			9,200			$	—			$	85	$	65	$	96.25
	2015(2)		Put spread		700			126,700			$	—			$	90	$	70	$	—
	2015		Put spread		250			91,250			$	—			$	89	$	69	$	—
	2015(3)		Put spread		600			110,400			$	—			$	87	$	67	$	—
	2016		Costless three-way collar		275			100,600			$	—			$	85	$	65	$	95.1
	2016		Costless three-way collar		330			120,780			$	—			$	80	$	65	$	97.35
	2016		Put spread		550			201,300			$	—			$	85	$	65	$	—
	2016		Put spread		300			109,800			$	—			$	85.5	$	65.5	$	—
	2017		Costless three-way collar		280			102,200			$	—			$	80	$	65	$	97.25
	2017		Costless three-way collar		242			88,150			$	—			$	80	$	60	$	98.7
	2017		Put spread		500			182,500			$	—			$	82	$	62	$	—
	2018(4)		Put spread		425			103,275			$	—			$	80	$	60	$	—
	_______________________________
	-1	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
	-2	For the period January to June 2015.
	-3	For the period July to December 2015.
	-4	For the period January to August 2018.
Natural Gas Liquids
Derivative [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of December 31, 2014, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base
					Daily			Notional			Fixed
					Volume			Volume			Price
					(in Bbls)
	2015(1)		Fixed price swap		250			68,750			$	45.61
	_______________________________
	-1	For the period April to December 2015.

Capital_Stock_Tables

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Schedule of Issuances And Forfeitures Of Common Shares	The following table provides information regarding the issuances and forfeitures of the Company's common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated:
		For the Years Ended December 31,
		2014	2013
	Other stock issuances:
	Shares of restricted common stock granted	601,473	2,288,179
	Shares of restricted common stock vested	1,915,242	762,682
	Shares of common stock issued pursuant to PBUs vested, net of forfeitures	472,189	—
	Stock options exercised	7,500	10,000
	Shares of restricted common stock surrendered upon vesting/exercise (1)	612,612	224,500
	Shares of restricted common stock forfeited	47,398	512,862
	_______________________________
	-1	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period.

Equity_Compensation_Plans_Tabl

Equity Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable	The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2014:
		Shares			Weighted Average			Weighted Average		Aggregate
					Exercise Price			Remaining		Intrinsic Value
					per Share			Contractual Term		(in thousands)
								(in years)
	Outstanding at December 31, 2013	874,100			$	11.68
	Granted	—			—
	Exercised	(7,500	)		2.6
	Canceled/Expired	—			—
	Forfeited	—			—
	Outstanding at December 31, 2014	866,600			$	11.75
	Options vested and exercisable at December 31, 2014	866,600			$	11.75		2.19		$	—
Schedule of Nonvested Share Activity
		Shares			Weighted Average			Weighted Average				Weighted Average	Aggregate
					Fair Value			Exercise Price				Remaining	Intrinsic Value
					per Share			per Share				Contractual Term	(in thousands)
												(in years)
	Outstanding non-vested options at December 31, 2013	10,000			$	2.74
	Granted	—			—
	Vested	(10,000	)		2.74
	Forfeited	—			—
	Outstanding non-vested options at December 31, 2014	—			$	—		$	—			0	$	—
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	The following table summarizes information related to restricted shares at December 31, 2014:
		Shares			Weighted  Average			Weighted Average		Aggregate
					Fair Value			Remaining		Intrinsic Value (in thousands)
					per Share			Contractual Term
								(in years)
	Outstanding non-vested restricted shares at December 31, 2013	3,773,081			$	1.82
	Granted	601,473			5.85
	Vested	(1,915,242	)		1.83
	Forfeited	(47,398	)		3.76
	Outstanding non-vested restricted shares at December 31, 2014	2,411,914			$	2.79		8.11		$	5,813
Schedule of Share-based Compensation, Stock Options, Activity	The table below provides a summary of PBUs as of the date indicated:
			PBUs			Fair Value per Unit
	Unvested PBUs at December 31, 2013		1,065,734			$	1.56
	Granted		280,171			7.34
	Vested		(355,247	)		1.56
	Forfeited		—			—
	Unvested PBUs at December 31, 2014		990,658			$	3.19
Schedule of Unrecognized Compensation Cost, Nonvested Awards	As of December 31, 2014, the Company had approximately $2.8 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods:
		Amount
		(in thousands)
	2015	$	2,034
	2016	663
	2017	59
	Total	$	2,756
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated:
		For the Years Ended December 31,
		2014				2013			2012
		(in thousands, except per share data)
	Weighted average grant date fair value per stock option granted	$	—			$	—		$	—
	Intrinsic value of stock options exercised (1)	$	28			$	19		$	2
	Grant date fair value of stock options vested	$	27			$	88		$	117
	_______________________________
	-1	Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.
Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated:
		For the Years Ended December 31,
		2014				2013			2012
		(in thousands, except per share data)
	Weighted average grant date fair value per restricted share	$	5.85			$	1.3		$	2.09
	Total fair value of restricted shares vested	$	3,497			$	2,725		$	2,492

Interest_Expense_Tables

Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2014
Interest Expense [Abstract]
Schedule of Components of Interest Expense	The following tables summarize the components of the Company's interest expense for the periods indicated:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Interest expense:
	Cash and accrued	$	28,851		$	14,130		$	1,992
	Amortization of deferred financing costs(1)(2)	3,067			2,322			224
	Capitalized interest	(4,347		)	(3,284		)	(1,946		)
	Total interest expense	$	27,571		$	13,168		$	270
	_______________________________
	-1	The year ended December 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. “Long-Term Debt - Second Amended and Restated Revolving Credit Facility.”
	-2	The years ended December 31, 2014 and 2013 include $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Contingency [Line Items]
Schedule of Income before Income Tax, Domestic and Foreign	The following table summarizes the components of the Company’s income (loss) before income taxes for the periods indicated:
		For the Year Ended December 31,
		2014			2013			2012
		(in thousands)
	United States	$	50,953		$	51,276		$	(152,322	)
	Foreign	—			(1,934		)	(1,469		)
	Total income (loss) before income taxes	$	50,953		$	49,342		$	(153,791	)
Schedule of Components of Income Tax Expense (Benefit)	The Company’s deferred income tax expense (benefit) consists of the following for the periods presented:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Deferred:
	Federal	$	—		$	(15,299	)	$	—
	State	—			(743		)	—
	Foreign	—			—			—
	Income tax expense (benefit)	$	—		$	(16,042	)	$	—
Schedule of Effective Income Tax Rate Reconciliation	The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Expected income tax provision (benefit) at statutory rate	$	17,833		$	11,655		$	(53,827	)
	State tax, tax effected	803			96			(2,562		)
	Stock-based compensation expense	(1,291		)	605			560
	Tax effect of Canadian tax rate differences	—			193			(125		)
	Loss of Canadian tax attributes due to migration from Canada	—			19,825			—
	Gain on acquisition of assets at fair value	—			(9,685		)	—
	Non-deductible costs of migration from Canada to U.S.	—			95			—
	Other	38			(49		)	15
	Other changes in valuation allowance	(17,383		)	(38,777		)	55,939
	Actual income tax provision	$	—		$	(16,042	)	$	—
US
Income Tax Contingency [Line Items]
Schedule of Deferred Tax Assets and Liabilities	The components of the Company’s U.S. deferred taxes are as follows:
		As of December 31,
		2014			2013
		(in thousands)
	Deferred tax asset (liability):
	Capital assets	$	(134,223	)	$	(77,456	)
	Stock-based compensation	4,504			6,501
	Net operating loss carry forwards	164,056			122,675
	Foreign tax credit carry forwards	50,681			50,681
	Valuation allowance	(85,018		)	(102,401		)
	Net deferred tax asset	$	—		$	—

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted
		For the Years Ended December 31,
		2014		2013		2012
		(in thousands, except per share and share data)
	Net income (loss) attributable to common stockholders	$	36,529	$	39,964	$	(160,868	)
	Weighted average shares of common stock outstanding - basic	63,270,733		60,220,115		63,538,362
	Incremental shares from unvested restricted shares	2,451,903		2,869,490		—
	Incremental shares from outstanding stock options	97,491		26,095		—
	Incremental shares from outstanding PBUs	672,462		502,701		—
	Weighted average shares of common stock outstanding - diluted	66,492,589		63,618,401		63,538,362
	Net income (loss) per share of common stock attributable to common stockholders:
	Basic	$	0.58	$	0.66	$	(2.53	)
	Diluted	$	0.55	$	0.63	$	(2.53	)
	Shares of common stock excluded from denominator as anti-dilutive:
	Unvested restricted shares	34,058		3,505		1,831,435
	Stock options	—		—		936,967
	Total	34,058		3,505		2,768,402

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of future minimum annual rental commitments	As of December 31, 2014, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows:
	2015	$	640
	2016	498
	2017	187
	2018	161
		$	1,486

Concentration_of_Risk_and_Sign1

Concentration of Risk and Significant Customers (Tables)	12 Months Ended
	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Schedules of Concentration of Risk, by Risk Factor	The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated:
			For the Years Ended December 31,
			2014		2013		2012
	Appalachian Basin		39	%	65	%	72	%
	Mid-Continent		61	%	26	%	—	%
	Hilltop Area, East Texas(1)		—	%	9	%	27	%
	Powder River Basin(2)		—	%	—	%	1	%
	_______________________________
	-1	The Company's working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013.
	-2	The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012.
	The following table provides information regarding our significant customers and the percentages of oil, condensate, natural gas and NGLs revenues, excluding hedge impact, which they represented for the periods indicated:
			For the Years Ended December 31,
			2014		2013		2012
	SEI		50	%	56	%	47	%
	Sunoco		37	%	16	%	—	%
	Clearfield Appalachian		—	%	8	%	14	%
	ETC		—	%	8	%	24	%

Statement_Of_Cash_Flows_Supple1

Statement Of Cash Flows - Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Statement Of Cash Flows Supplemental Information	The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:
		For the Years Ended December 31,
		2014			2013			2012
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	24,632		$	7,341		$	39
	Non-cash transactions:
	Capital expenditures included in accounts payable and accrued drilling costs	$	12,777		$	582		$	4,666
	Capital expenditures included in accounts receivable	4,077			(4,077		)	(929		)
	Asset retirement obligation included in oil and natural gas properties	221			(1,302		)	1,164
	Asset retirement obligation sold/assigned to operator	(645		)	(4,354		)	(2,227		)
	Application of advances to operators	58,326			19,755			7,441
	Other	(11		)	47			(36		)

Quarterly_Consolidated_Financi1

Quarterly Consolidated Financial Data - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2014 and 2013:
		2014
		First			Second		Third			Fourth
		Quarter			Quarter		Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	32,327		$	35,897	$	41,746		$	61,448
	Income from operations	8,497			12,539		20,413			37,063
	Income before provision for income taxes	1,611			5,627		13,425			30,290
	Net income	1,611			5,627		13,425			30,290
	Dividend on preferred stock	3,576			3,611		3,618			3,619
	Net (loss) income attributable to common stockholders	(1,965		)	2,016		9,807			26,671
	Net (loss) income per share of common stock attributable to common stockholders:
	Basic	$	(0.03	)	$	0.03	$	0.16		$	0.35
	Diluted	$	(0.03	)	$	0.03	$	0.15		$	0.34
	Weighted average shares of common stock outstanding:
	Basic	58,204,532			58,702,982		60,006,903			75,994,979
	Diluted	58,204,532			61,922,874		63,399,446			78,577,762
		2013
		First			Second		Third			Fourth
		Quarter			Quarter		Quarter			Quarter
		(in thousands, except share and per share data)
	Revenues	$	11,264		$	30,926	$	18,840		$	26,725
	(Loss) income from operations	(1,849		)	13,809		1,626			5,178
	(Loss) income before provision for income taxes(1)	(2,456		)	53,970		(1,808		)	(16,406		)
	Net (loss) income	(2,456		)	53,970		(1,808		)	(364		)
	Dividend on preferred stock	2,130			2,134		2,134			2,980
	Net (loss) income attributable to common stockholders	(4,586		)	51,836		(3,942		)	(3,344		)
	Net (loss) income per share of common stock attributable to common stockholders:
	Basic	$	(0.07	)	$	0.83	$	(0.07	)	$	(0.06	)
	Diluted	$	(0.07	)	$	0.81	$	(0.07	)	$	(0.06	)
	Weighted average shares of common stock outstanding:
	Basic	63,864,527			62,398,472		57,359,357			57,433,550
	Diluted	63,864,527			63,813,423		57,359,357			57,433,550
	_________________________________
	-1	Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.

Supplemental_Oil_and_Gas_Discl1

Supplemental Oil and Gas Disclosures - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2014
Reserve Quantities [Line Items]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities for the periods indicated:
		As of December 31,
		2014				2013				2012
		(in thousands)
	Proved properties:
	United States	$	1,124,367			$	935,773			$	671,193
	Total proved properties	1,124,367				935,773				671,193
	Unproved properties:
	United States	128,274				96,220				67,892
	Total unproved properties	128,274				96,220				67,892
	Total oil and natural gas properties	1,252,641				1,031,993				739,085
	Less:
	Impairment of proved oil and natural gas properties
	United States	(337,939		)		(337,939		)		(337,939		)
	Accumulated depreciation, depletion and amortization	(223,555		)		(177,790		)		(145,631		)
	Net capitalized costs	$	691,147			$	516,264			$	255,515
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	The following table sets forth costs incurred related to the Company’s oil and natural gas activities in the U.S. for the periods indicated:
			For the years ended December 31,
			2014				2013				2012
			(in thousands)
	Property acquisition
	Proved(1)		$	—			$	189,594			$	—
	Unproved(2)		41,475				71,472				25,676
	Exploration		127,384				36,893				10,041
	Development		57,913				53,058				111,878
	Total costs incurred		$	226,772			$	351,017			$	147,595
	_________________________________
	-1	The 2013 property acquisition costs exclude a downward adjustment of $2.6 million for fair value of acquisition.
	-2	The 2013 property acquisition costs exclude $46.3 million of adjustment for fair value of acquisitio
Results of Operations for Oil and Gas Producing Activities Disclosure	The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated:
		For the Year Ended December 31,
		2014				2013				2012
		(in thousands, except per Mcfe data)
	Oil, condensate, natural gas and NGLs sales, including commodity derivatives	$	171,418			$	87,755			$	49,940
	Production expenses	(29,735		)		(18,113		)		(13,408		)
	Impairment of oil and natural gas properties	—				—				(150,787		)
	Depreciation, depletion and amortization	(45,765		)		(32,158		)		(25,195		)
	Results of producing activities	$	95,918			$	37,484			$	(139,450	)
	Depreciation, depletion and amortization per MBoe	$	12.34			$	9.94			$	11.41
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations:
		For the Years Ended December 31,
		2014				2013				2012
	Natural gas, per MMBtu
	Henry Hub	$	4.35			$	3.67			$	2.76
	Oil, per barrel:
	WTI spot	$	94.99			$	96.78			$	94.71
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2014, 2013 and 2012:
	Change in Proved Reserves	Natural  Gas			NGLs			Condensate and Oil			MBoe (3) Equivalents (4)
		(MMcf) (1)			(MBbl) (2)			(MBbl) (2)
	Proved reserves as of December 31, 2011	91,652			2,757			1,921			19,953
	2012 Activity:
	Extensions and discoveries(5)	57,835			2,783			2,439			14,861
	Revisions of previous estimates	(6,518	)		(348	)		(796	)		(2,230	)
	Production	(10,564	)		(270	)		(177	)		(2,208	)
	Purchases in place	—			—			7			7
	Sales in place	(1,395	)		—			—			(231	)
	Proved reserves as of December 31, 2012	131,010			4,922			3,394			30,152
	2013 Activity:
	Extensions and discoveries(6)	52,750			2,306			4,385			15,483
	Revisions of previous estimates	8,114			714			(337	)		1,729
	Production	(13,366	)		(494	)		(515	)		(3,237	)
	Purchases in place	26,961			2,350			7,796			14,639
	Sales in place	(24,759	)		—			(5	)		(4,132	)
	Proved reserves as of December 31, 2013	180,710			9,798			14,718			54,634
	2014 Activity:
	Extensions and discoveries(7)	121,672			9,394			13,137			42,810
	Revisions of previous estimates	(2,465	)		7,205			1,780			8,574
	Production	(11,598	)		(800	)		(975	)		(3,708	)
	Sales in place	(1,314	)		(4	)		(24	)		(247	)
	Proved reserves as of December 31, 2014	287,005			25,593			28,636			102,063
	_________________________________
	(1)Million cubic feet or million cubic feet equivalent, as applicable
	-2	Thousand barrels
	-3	Thousand barrels of oil, condensate or NGLs equivalent.
	-4	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
	-5	The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery.
	-6	Of the 2013 extensions and discoveries, 74% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
	-7	Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
	Proved Developed and Undeveloped Reserves	Natural Gas			NGLs			Condensate and Oil			MBoe (3) Equivalents (4)
		(MMcf) (1)			(MBbl) (2)			(MBbl) (2)
	31-Dec-12
	Proved developed reserves	95,602			3,215.80			1,959			21,109
	Proved undeveloped reserves	35,408			1,706			1,435			9,042
	Total	131,010			4,922			3,394			30,151
	31-Dec-13
	Proved developed reserves	114,195			6,025			5,834			30,892
	Proved undeveloped reserves	66,515			3,773			8,884			23,742
	Total	180,710			9,798			14,718			54,634
	31-Dec-14
	Proved developed reserves	114,564			10,726			6,968			36,789
	Proved undeveloped reserves	172,441			14,867			21,668			65,274
	Total	287,005			25,593			28,636			102,063
	_________________________________
	(1)Million cubic feet or million cubic feet equivalent, as applicable
	-2	Thousand barrels
	-3	Thousand barrels of oil, condensate or NGLs equivalent.
	-4	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is presented below:
		United States
		(in thousands)
	December 31, 2012:
	Future cash inflows	$	672,142
	Future production costs	(167,864		)
	Future development costs	(83,697		)
	Future income taxes(1)	—
	Future net cash flows	420,581
	10% annual discount for estimated timing of cash flows	(213,772		)
	Standardized measure of discounted future cash flows	$	206,809
	December 31, 2013:
	Future cash inflows	$	2,103,023
	Future production costs	(588,568		)
	Future development costs	(296,666		)
	Future income taxes	(215,502		)
	Future net cash flows	1,002,287
	10% annual discount for estimated timing of cash flows	(486,458		)
	Standardized measure of discounted future cash flows	$	515,829
	December 31, 2014:
	Future cash inflows	$	3,855,227
	Future production costs	(1,048,554		)
	Future development costs	(611,602		)
	Future income taxes	(486,593		)
	Future net cash flows	1,708,478
	10% annual discount for estimated timing of cash flows	(891,739		)
	Standardized measure of discounted future cash flows	$	816,739
	_________________________________
	-1	No future taxes payable has been included in the determination of discounted future net cash flows for 2012 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	The principal sources of changes in the standardized measure of future net cash flows are as follows:
		United States
		(in thousands)
	December 31, 2011	$	212,783
	Extensions and discoveries, less related costs	112,390
	Sale of natural gas and oil, net of production costs	(29,110		)
	Purchases of reserves in place	64
	Sales of reserves in place	(216		)
	Revisions of previous quantity estimates	(30,959		)
	Net change in income tax	4,334
	Net change in prices and production costs	(98,589		)
	Accretion of discount	1,152
	Development costs incurred	19,702
	Net change in estimated future development costs	2,518
	Change in production rates (timing) and other	12,740
	31-Dec-12	$	206,809
	Extensions and discoveries, less related costs	196,448
	Sale of natural gas and oil, net of production costs	(74,394		)
	Purchases of reserves in place	247,208
	Sales of reserves in place	(9,063		)
	Revisions of previous quantity estimates	6,191
	Net change in income tax	(76,701		)
	Net change in prices and production costs	79,820
	Accretion of discount	1,211
	Development costs incurred	23,567
	Net change in estimated future development costs	(97,461		)
	Change in production rates (timing) and other	12,194
	31-Dec-13	$	515,829
	Extensions and discoveries, less related costs	369,806
	Sale of natural gas and oil, net of production costs	(122,114		)
	Sales of reserves in place	(1,475		)
	Revisions of previous quantity estimates	101,044
	Net change in income tax	(95,245		)
	Net change in prices and production costs	59,786
	Accretion of discount	(3,996		)
	Development costs incurred	37,461
	Net change in estimated future development costs	(1,277		)
	Change in production rates (timing) and other	(43,081		)
	31-Dec-14	$	816,739
Key Natural Gas and Oil Prices
Reserve Quantities [Line Items]
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves:
		As of December 31,
		2014				2013
	Natural gas (per MMBtu):
	Henry Hub	$	4.35			$	3.67
	Oil (per Bbl):
	WTI spot	$	94.99			96.78

Recovered_Sheet2

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Line Items]
Cash and cash equivalents	$11,008	$32,393	$8,901	$10,647
Capitalized interest	($4,347)	($3,284)	($1,946)
Canada
Accounting Policies [Line Items]
Number of gas wells	2
Minimum | Furniture and equipment
Accounting Policies [Line Items]
Estimated useful lives	3 years
Maximum | Furniture and equipment
Accounting Policies [Line Items]
Estimated useful lives	7 years

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Schedule of Allowance for Doubtful Accounts) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Allowance for Doubtful Accounts Receivable [Roll Forward]
Allowance for doubtful accounts, beginning of year	$507	$546	$551
Expense	0	0	0
Reductions/write-offs	-507	-39	-5
Allowance for doubtful accounts, end of year	$0	$507	$546

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Schedule of Deferred Financing Costs) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Deferred charges	$3,664	$3,269
Accumulated amortization	-1,078	-319
Deferred charges, net	$2,586	$2,950

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule of Property Plant and Equipment) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]
Unproved properties	$128,274	$96,220	$67,892
Proved properties	1,124,367	935,773	671,193
Total oil and natural gas properties	1,252,641	1,031,993
Total property and equipment	1,255,651	1,034,684
Impairment of proved natural gas and oil properties	-337,939	-337,939
Accumulated depreciation, depletion and amortization	-225,412	-179,232
Total accumulated depreciation, depletion and amortization	-563,351	-517,171
Total property, plant and equipment, net	692,300	517,513
Total oil and natural gas properties
Property, Plant and Equipment [Line Items]
Unproved properties	128,274	96,220
Proved properties	1,124,367	935,773
Total oil and natural gas properties	1,252,641	1,031,993
Furniture and equipment
Property, Plant and Equipment [Line Items]
Total property and equipment	$3,010	$2,691

Property_Plant_And_Equipment_N

Property, Plant And Equipment (Narrative) (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Jun. 30, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Nov. 01, 2010

Dec. 31, 2011

Jul. 01, 2013

Jan. 01, 2013

Jun. 07, 2013

Nov. 15, 2013

Oct. 02, 2013

Aug. 06, 2013

Jul. 02, 2013

Mar. 28, 2013

Sep. 04, 2013

well

acre

acre

acre

acre

acre

well

Property, Plant and Equipment [Line Items]

Asset retirement obligation

$2,400,000

$3,400,000

$4,800,000

Gain on acquisition of assets at fair value, net of income taxes

43,700,000

0

27,670,000

0

Proceeds from sale of natural gas and oil properties

5,530,000

112,201,000

0

Term of development program

3 years

Atinum Joint Venture

Property, Plant and Equipment [Line Items]

Net acres

34,200

Productive conventional wells (wells)

16

Working interest In wells (percentage)

50.00%

Gross acres

37,600

Initial interest in assets (percentage)

21.43%

Non productive number of wells

1

Proceeds from sale of Marcellus Shale assets

30,000,000

Cash received from Atinum for drilling carrying costs

40,000,000

40,000,000

Atinum ownership interest in Atinum Joint Venture Assets (percentage)

50.00%

Percentage of share of drilling completion and infrastructure costs carried (percentage)

75.00%

Joint interest share of drilling completion and infrastructure costs (percentage)

50.00%

50.00%

Gross operated wells drilled, completed and on production

67

Operated wells drilled, completed and on production

32

Percentage of reimbursements for lease bonuses and third party lease costs up to 20 million (percentage)

10.00%

Percentage of lease operating expenses covered (percentage)

5.00%

East Texas

Property, Plant and Equipment [Line Items]

Reclassification of unproved properties to proved properties

3,300,000

20,500,000

Gastar Exploration USA | Hunton Joint Venture

Property, Plant and Equipment [Line Items]

Net acres

12,800

Transaction and integration costs

133,000

Acquisition of oil and natural gas properties

11,800,000

Gastar Exploration USA | East Texas

Property, Plant and Equipment [Line Items]

Net acres

16,300

Gross acres

31,800

Proceeds from sale of natural gas and oil properties

42,900,000

Gastar Exploration USA | Utica Shale | Atinum Joint Venture

Property, Plant and Equipment [Line Items]

Productive conventional wells (wells)

1

Operated wells drilled, completed and on production

0.5

Gastar Exploration USA | Hunton Divestiture

Property, Plant and Equipment [Line Items]

Net acres

76,000

Net cash purchase price of divestiture

57,000,000

Gastar Exploration USA | Chesapeake Assets

Property, Plant and Equipment [Line Items]

Net acres

157,000

Productive conventional wells (wells)

206

Cash consideration

69,400,000

Fair market valuation amount

113,083,000

Gain on acquisition of assets at fair value, net of income taxes

27,670,000

Income tax expense recognized

16,042,000

Gastar Exploration USA | Chesapeake Assets | General and Administrative Expense

Property, Plant and Equipment [Line Items]

Transaction and integration costs

2,100,000

Gastar Exploration USA | Oklahoma Oil and Gas Leasehold Interests

Property, Plant and Equipment [Line Items]

Net acres

1,850

Gastar Exploration USA | WEHLU Purchase Agreement

Property, Plant and Equipment [Line Items]

Net acres

24,000

Cash consideration

177,778,000

Transaction and integration costs

286,000

Fair market valuation amount

177,778,000

Working interest In wells (percentage)

98.30%

Net revenue interest

80.50%

Preliminary assessment of fair value of WEHLU Assets

$176,800,000

Minimum | Atinum Joint Venture

Property, Plant and Equipment [Line Items]

Amended required exploratory wells drilled net productive to be drilled in current fiscal year (wells)

51

Maximum | Gastar Exploration USA | Atinum Joint Venture

Property, Plant and Equipment [Line Items]

Gross wells originally agreed upon

60

Property_Plant_And_Equipment_S1

Property, Plant And Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Unproved properties, excluded from amortization:
Drilling in progress costs	$29,193	$4,774
Acreage acquisition costs	91,362	86,097
Capitalized interest	7,719	5,349
Total unproved properties excluded from amortization	$128,274	$96,220

Property_Plant_And_Equipment_S2

Property, Plant And Equipment (Schedule of Relevant Assumptions Used In Ceiling Test Computations) (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

In Thousands, unless otherwise specified

Sep. 30, 2014

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2012

Jun. 30, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 31, 2012

Average Sales Price and Production Costs Per Unit of Production [Line Items]

Impairment of natural gas and oil properties

$0

$0

$0

$0

$78,054

$72,733

$0

$0

$150,787

Henry Hub natural gas price (per MMBtu)

Average Sales Price and Production Costs Per Unit of Production [Line Items]

Key natural gas and oil prices

4.24

[1]

4.1

[1]

3.61

[1]

3.44

[1]

2.83

[1]

3.15

[1]

4.35

[1]

3.99

[1]

3.67

[1]

2.95

[1]

2.76

[1]

3.73

[1]

West Texas Intermediate oil price (per Bbl)

Average Sales Price and Production Costs Per Unit of Production [Line Items]

Key natural gas and oil prices

99.08

[1]

100.11

[1]

91.69

[1]

88.13

[1]

91.48

[1]

92.17

[1]

94.99

[1]

98.3

[1]

96.78

[1]

89.17

[1]

91.21

[1]

94.65

[1]

[1]

For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Property_Plant_And_Equipment_S3

Property, Plant And Equipment (Schedule of Assets Acquired) (Details) (USD $)	3 Months Ended	12 Months Ended			0 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 07, 2013	Nov. 15, 2013
Business Acquisition [Line Items]
Gain on acquisition of assets at fair value, net of income taxes	$43,700	$0	$27,670	$0
Chesapeake Assets | Gastar Exploration USA
Business Acquisition [Line Items]
Cash consideration					69,371
Deferred tax liability					16,042
Total purchase price plus liabilities assumed					85,413
Cash consideration					69,400
Unproved properties					86,327
Proved properties					26,756
Total assets acquired					113,083
Gain on acquisition of assets at fair value, net of income taxes					27,670
WEHLU Purchase Agreement | Gastar Exploration USA
Business Acquisition [Line Items]
Cash consideration						177,778
Unproved properties						13,026
Proved properties						164,752
Total assets acquired						$177,778

Property_Plant_And_Equipment_S4

Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) (WEHLU Purchase Agreement, Gastar Exploration USA, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
WEHLU Purchase Agreement | Gastar Exploration USA
Business Acquisition [Line Items]
Revenues	$132,721	$97,760
Net Loss	-4,836	-175,809
Loss per share, Basic	($0.08)	($2.77)
Loss per share, Diluted	($0.08)	($2.77)
Revenues	11,292
Excess of revenues over direct operating expenses	$7,591

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

15-May-13

Dec. 31, 2014

Jun. 07, 2013

Dec. 31, 2013

Mar. 09, 2015

Mar. 08, 2015

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Sep. 29, 2016

Mar. 31, 2016

Mar. 30, 2016

Jun. 30, 2016

Jun. 29, 2016

Line of Credit Facility [Line Items]

Long-term debt

$360,303,000

$312,994,000

Second Amended and Restated Revolving Credit Facility | Subsequent Event

Line of Credit Facility [Line Items]

Revolving credit facility borrowing base

200,000,000

145,000,000

Second Amended and Restated Revolving Credit Facility | Subsequent Event | Scenario, Forecast

Line of Credit Facility [Line Items]

Leverage ratio

4

4.25

4.75

5

5.25

Interest coverage ratio

2.5

2

Senior Notes | Senior Secured Notes Due 2018

Line of Credit Facility [Line Items]

Aggregate principal amount

325,000,000

Interest rate

8.63%

8.63%

Redemption percentage of aggregate principal amount

101.00%

Long-term debt

315,300,000

Unamortized discounts

9,700,000

Senior Notes | Senior Secured Notes Due 2018 | Subsequent Event | Scenario, Forecast

Line of Credit Facility [Line Items]

Leverage ratio

2

2.25

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility

Line of Credit Facility [Line Items]

Annual commitment fee (percentage)

0.50%

Percentage of stock foreign subsidiary pledged as collateral for credit facility (percentage)

65.00%

Line of credit facility covenant compliance EBITDA to Interest Expense Ratio on a four quarter rolling basis

2.5

Revolving credit facility borrowing base

145,000,000

50,000,000

Revolving Credit Facility, remaining borrowing capacity

100,000,000

Revolving Credit Facility amount outstanding

$45,000,000

Percentage increase in adjusted consolidated net tangible assets

17.50%

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Minimum

Line of Credit Facility [Line Items]

Line of credit facility covenant compliance Current Ratio

1

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Maximum

Line of Credit Facility [Line Items]

Line of credit facility covenant compliance indebtedness to EBITDA Ratio

4

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Federal Funds Rate

Line of Credit Facility [Line Items]

Federal funds rate

federal funds rate plus

Applicable interest rate margin

0.50%

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | LIBOR

Line of Credit Facility [Line Items]

Applicable interest rate margin

1.00%

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Prime Rate | Minimum

Line of Credit Facility [Line Items]

Applicable interest rate margin

1.00%

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Prime Rate | Maximum

Line of Credit Facility [Line Items]

Applicable interest rate margin

2.00%

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Eurodollar | Minimum

Line of Credit Facility [Line Items]

Applicable interest rate margin

2.00%

Gastar Exploration USA | Second Amended and Restated Revolving Credit Facility | Eurodollar | Maximum

Line of Credit Facility [Line Items]

Applicable interest rate margin

3.00%

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning of year	$6,063	$6,963	$8,275
Liabilities incurred during period	305	3,416	271
Liabilities settled during period	-704	-126	-297
Accretion of asset retirement obligation	506	468	388
Revision in previous estimates and other	32	60	553
Deletions related to property disposals	-645	-4,718	-2,227
Asset retirement obligation, end of year	5,557	6,063	6,963
Asset retirement obligation	$82	$633

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Estimated fair value of long term debt	$330.60	$324.60
East Texas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Reclassification of unproved properties to proved properties	$3.30	$20.50

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	$27,502	$7,545
Derivative Liabilities [Abstract]
Liabilities, Commodity derivative contracts	0	-3,781
Total	38,510	36,157
Level 1
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	0	0
Derivative Liabilities [Abstract]
Liabilities, Commodity derivative contracts	0	0
Total	11,008	32,393
Level 2
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	0	0
Derivative Liabilities [Abstract]
Liabilities, Commodity derivative contracts	0	0
Total	0	0
Level 3
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	27,502	7,545
Derivative Liabilities [Abstract]
Liabilities, Commodity derivative contracts	0	-3,781
Total	27,502	3,764
Cash and cash equivalents
Derivative Assets [Abstract]
Cash and cash equivalents	11,008	32,393
Cash and cash equivalents | Level 1
Derivative Assets [Abstract]
Cash and cash equivalents	11,008	32,393
Cash and cash equivalents | Level 2
Derivative Assets [Abstract]
Cash and cash equivalents	0	0
Cash and cash equivalents | Level 3
Derivative Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash
Derivative Assets [Abstract]
Cash and cash equivalents		0
Restricted cash | Level 1
Derivative Assets [Abstract]
Cash and cash equivalents		0
Restricted cash | Level 2
Derivative Assets [Abstract]
Cash and cash equivalents		0
Restricted cash | Level 3
Derivative Assets [Abstract]
Cash and cash equivalents		$0

Fair_Value_Measurements_Net_Ch

Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) (Fair Value, Inputs, Level 3, Commodity, Fair Value, Measurements, Recurring, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Measurements, Recurring
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$3,764		$6,465
Total gains (losses)
included in earnings	19,569		-4,752
Purchases	369		9,772
Issuances	0		-2,308
Settlements	3,800	[1]	-5,413	[1]
Balance at end of period	27,502		3,764
The amount of total gains (losses) for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2014 and 2013	$23,902		($9,967)
[1]	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations.

Derivative_Instruments_And_Hed2

Derivative Instruments And Hedging Activity (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of commodity derivative instruments	$23.90	($10)	($5.60)

Derivative_Instruments_And_Hed3

Derivative Instruments And Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2014
	MMBTU
Natural Gas | 2015 | Call spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000	[1]
Total of Notional Volume (MMBtu's or Bbls)	900,000	[1]
Base Fixed Price (Price per MMbtu or Bbl)	0	[1]
Ceiling (Short) (Price per MMBtu)	5	[1]
Natural Gas | 2016 | Protective spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	732,000
Base Fixed Price (Price per MMbtu or Bbl)	4.11
Short Put (Price per MMBtu)	3.25
Crude Oil | 2015 | Costless three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400	[2],[3]
Total of Notional Volume (MMBtu's or Bbls)	73,600	[3]
Floor (Long) (Price per MMBtu)	85	[3]
Short Put (Price per MMBtu)	70	[3]
Ceiling (Short) (Price per MMBtu)	96.5	[3]
Crude Oil | 2016 | Costless three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	275	[2],[4]
Total of Notional Volume (MMBtu's or Bbls)	100,600	[4]
Floor (Long) (Price per MMBtu)	85	[4]
Short Put (Price per MMBtu)	65	[4]
Ceiling (Short) (Price per MMBtu)	95.1
Crude Oil | 2017 | Costless three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	280	[2]
Total of Notional Volume (MMBtu's or Bbls)	102,200
Floor (Long) (Price per MMBtu)	80
Short Put (Price per MMBtu)	65
Ceiling (Short) (Price per MMBtu)	97.25
Crude Oil | 2017 | Put spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	500	[2]
Total of Notional Volume (MMBtu's or Bbls)	182,500
Floor (Long) (Price per MMBtu)	82
Short Put (Price per MMBtu)	62
Crude Oil | 2018 | Put spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	425	[2],[4]
Total of Notional Volume (MMBtu's or Bbls)	103,275	[4]
Floor (Long) (Price per MMBtu)	80	[4]
Short Put (Price per MMBtu)	60	[4]
Natural Gas Liquids | 2015 | Fixed price swap
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	250	[5]
Total of Notional Volume (MMBtu's or Bbls)	68,750	[5]
Base Fixed Price (Price per MMbtu or Bbl)	45.61	[5]
Protective Spread 1 | Natural Gas | 2015 | Protective spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000	[1]
Total of Notional Volume (MMBtu's or Bbls)	900,000	[1]
Base Fixed Price (Price per MMbtu or Bbl)	4.46	[1]
Short Put (Price per MMBtu)	3.7	[1]
Protective Spread 2 | Natural Gas | 2015 | Protective spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,600
Total of Notional Volume (MMBtu's or Bbls)	949,000
Base Fixed Price (Price per MMbtu or Bbl)	4
Short Put (Price per MMBtu)	3.25
Costless Collar 1 | Crude Oil | 2015 | Costless collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400	[2],[6]
Total of Notional Volume (MMBtu's or Bbls)	72,400	[6]
Floor (Long) (Price per MMBtu)	85	[6]
Ceiling (Short) (Price per MMBtu)	96.5	[6]
Costless Collar 2 | Crude Oil | 2015 | Costless collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	366	[2],[6]
Total of Notional Volume (MMBtu's or Bbls)	66,300	[6]
Floor (Long) (Price per MMBtu)	85	[6]
Ceiling (Short) (Price per MMBtu)	97.8	[6]
Costless Collar 3 | Crude Oil | 2015 | Costless collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	150	[2],[6]
Total of Notional Volume (MMBtu's or Bbls)	27,150	[6]
Floor (Long) (Price per MMBtu)	85	[3]
Ceiling (Short) (Price per MMBtu)	96.25	[6]
Fixed Price Swap 1 | Natural Gas | 2015 | Fixed price swap
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400
Total of Notional Volume (MMBtu's or Bbls)	146,000
Base Fixed Price (Price per MMbtu or Bbl)	4
Fixed Price Swap 2 | Natural Gas | 2015 | Fixed price swap
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	912,500
Base Fixed Price (Price per MMbtu or Bbl)	4.06
Producer Three Way Collar 1 | Natural Gas | 2015 | Producer three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	3,750	[1]
Total of Notional Volume (MMBtu's or Bbls)	337,500	[1]
Floor (Long) (Price per MMBtu)	4.6	[1]
Short Put (Price per MMBtu)	3.5	[1]
Ceiling (Short) (Price per MMBtu)	5.34	[1]
Producer Three Way Collar Two | Natural Gas | 2015 | Producer three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[1]
Total of Notional Volume (MMBtu's or Bbls)	337,500	[1]
Floor (Long) (Price per MMBtu)	4.4	[1]
Short Put (Price per MMBtu)	3.65	[1]
Ceiling (Short) (Price per MMBtu)	5	[1]
Producer Three Way Collar Three | Natural Gas | 2015 | Producer three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	760,000
Floor (Long) (Price per MMBtu)	4
Short Put (Price per MMBtu)	3.25
Ceiling (Short) (Price per MMBtu)	4.58
Basis Swap 1 | Natural Gas | 2015 | Basis Swap [Member]
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	912,500	[7]
Base Fixed Price (Price per MMbtu or Bbl)	-1.12	[7]
Basis Swap 2 | Natural Gas | 2015 | Basis Swap [Member]
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	912,500	[7]
Base Fixed Price (Price per MMbtu or Bbl)	-1.11	[7]
Basis Points 3 | Natural Gas | 2015 | Basis Swap [Member]
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	912,500	[7]
Base Fixed Price (Price per MMbtu or Bbl)	-1.14	[7]
Protective Spread 3 | Natural Gas | 2015 | Protective spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000	[5]
Total of Notional Volume (MMBtu's or Bbls)	1,375,000	[5]
Base Fixed Price (Price per MMbtu or Bbl)	4	[5]
Short Put (Price per MMBtu)	3.25	[5]
Producer Three Way Collar 4 | Natural Gas | 2015 | Producer three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[5]
Total of Notional Volume (MMBtu's or Bbls)	687,500	[5]
Floor (Long) (Price per MMBtu)	3.7	[5]
Short Put (Price per MMBtu)	3	[5]
Ceiling (Short) (Price per MMBtu)	4.09	[5]
Producer Three Way Collar 5 | Natural Gas | 2015 | Producer three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000	[5]
Total of Notional Volume (MMBtu's or Bbls)	1,375,000	[5]
Floor (Long) (Price per MMBtu)	3.77	[5]
Short Put (Price per MMBtu)	3	[5]
Ceiling (Short) (Price per MMBtu)	4.11	[5]
Costless Three Way Collar 2 | Crude Oil | 2015 | Costless three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	325	[2],[3]
Total of Notional Volume (MMBtu's or Bbls)	59,800	[3]
Floor (Long) (Price per MMBtu)	85	[3]
Short Put (Price per MMBtu)	65	[3]
Ceiling (Short) (Price per MMBtu)	97.8	[3]
Costless Three Way Collar 2 | Crude Oil | 2016 | Costless three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	330	[2]
Total of Notional Volume (MMBtu's or Bbls)	120,780
Floor (Long) (Price per MMBtu)	80
Short Put (Price per MMBtu)	65
Ceiling (Short) (Price per MMBtu)	97.35
Costless Three Way Collar 2 | Crude Oil | 2017 | Costless three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	242	[2]
Total of Notional Volume (MMBtu's or Bbls)	88,150
Floor (Long) (Price per MMBtu)	80
Short Put (Price per MMBtu)	60
Ceiling (Short) (Price per MMBtu)	98.7
Cost Less Three Way Collar 3 | Crude Oil | 2015 | Costless three-way collar
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	50	[2],[3]
Total of Notional Volume (MMBtu's or Bbls)	9,200	[3]
Floor (Long) (Price per MMBtu)	85	[3]
Short Put (Price per MMBtu)	65	[3]
Ceiling (Short) (Price per MMBtu)	96.25	[3]
Put Spread 1 | Crude Oil | 2015 | Put spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	700	[2],[6]
Total of Notional Volume (MMBtu's or Bbls)	126,700	[6]
Floor (Long) (Price per MMBtu)	90	[6]
Short Put (Price per MMBtu)	70	[6]
Put Spread 1 | Crude Oil | 2016 | Put spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	550	[2]
Total of Notional Volume (MMBtu's or Bbls)	201,300
Floor (Long) (Price per MMBtu)	85
Short Put (Price per MMBtu)	65
Put Spread 2 | Crude Oil | 2015 | Put spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	250	[2]
Total of Notional Volume (MMBtu's or Bbls)	91,250
Floor (Long) (Price per MMBtu)	89	[4]
Short Put (Price per MMBtu)	69	[4]
Put Spread 2 | Crude Oil | 2016 | Put spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	300	[2]
Total of Notional Volume (MMBtu's or Bbls)	109,800
Floor (Long) (Price per MMBtu)	85.5
Short Put (Price per MMBtu)	65.5
Put Spread 3 | Crude Oil | 2015 | Put spread
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	600	[2],[3]
Total of Notional Volume (MMBtu's or Bbls)	110,400	[3]
Floor (Long) (Price per MMBtu)	87	[3]
Short Put (Price per MMBtu)	67	[3]
[1]	For the period January to March 2015.
[2]	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
[3]	For the period July to December 2015.
[4]	For the period January to August 2018.
[5]	For the period April to December 2015.
[6]	For the period January to June 2015.
[7]	Represents basis swaps at the sales point of Dominion South.

Derivative_Instruments_And_Hed4

Derivative Instruments And Hedging Activity (Schedule of Unamortized Put Premium) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative premium payable	$2,481	$145
Commodity derivative premium payable	4,702	7,000
Total unamortized put premium liabilities	$7,183	$7,145

Derivative_Instruments_And_Hed5

Derivative Instruments And Hedging Activity (Schedule of Deferred Put Premium Liability) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Put Premium Liabilities [Roll Forward]
Put premium liabilities, beginning balance	$7,145
Amortization of put premium liabilities	-145
Additional put premium liabilities	183
Put premium liabilities, ending balance	$7,183

Derivative_Instruments_And_Hed6

Derivative Instruments And Hedging Activity (Schedule of Future Amortization of Put Premium) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
January to December 2015	$2,481
January to December 2016	2,408
January to December 2017	1,460
January to August 2018	834
Total unamortized put premium liabilities	$7,183	$7,145

Derivative_Instruments_And_Hed7

Derivative Instruments And Hedging Activity (Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location) (Details) (Not Designated as Hedging Instrument, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Total derivatives not designated as hedging instruments	$27,502	$3,764
Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31,	19,569	-4,752	7,236
Gain (loss) on commodity derivatives contracts
Derivatives, Fair Value [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31,	19,569	-4,752	7,422
Interest expense
Derivatives, Fair Value [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives For the Years Ended December 31,	0	0	-186
Current assets
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	19,687	0
Other assets
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	7,815	7,545
Current liabilities
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	0	-3,403
Long-term liabilities
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	$0	($378)

Capital_Stock_Narrative_Detail

Capital Stock (Narrative) (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 24, 2014	Jun. 23, 2011	Nov. 07, 2013	Oct. 29, 2013	Jun. 07, 2013	Apr. 24, 2014	Nov. 14, 2013	Jun. 03, 2012	Jun. 02, 2012	Oct. 25, 2013	Oct. 24, 2013	24-May-11	Nov. 01, 2013	Jun. 29, 2011
Class of Stock [Line Items]
Common shares authorized for issuance (shares)	275,000,000	275,000,000								275,000,000
Common stock, par value	$0.00	$0.00								$0.00
Common shares issued (shares)	78,632,810	61,211,658
Proceeds from issuance of common shares, net of issuance costs	$101,319,000	$0	$0
Proceeds from issuance of preferred stock and preference stock	2,064,000	50,183,000	49,250,000
Preferred stock dividends	14,424,000	9,378,000	7,077,000
Common shares reserved for the exercise of stock options (shares)											11,000,000	6,000,000
Repurchase of common shares	0	9,753,000	0
Series B Preferred Stock
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)	10,000,000	10,000,000
Preferred stock par value per share	$0.01	$0.01
Preferred stock, shares sold (shares)	2,140,000	2,140,000
Redemption Price	$25	$25
On or after June 23, 2014
Class of Stock [Line Items]
Redemption Price	$25
Gastar Exploration USA
Class of Stock [Line Items]
Common shares authorized for issuance (shares)													275,000,000	1,000	1,000
Common stock, par value													$0.00
Common shares issued (shares)		750	750												750
Shares of common stock in underwritten public offering				17,000,000
Price per share of underwritten public offering				$6.25
Sales price of underwritten public offering before offering costs and expenses				106,300,000
Proceeds from issuance of common shares, net of issuance costs				101,300,000
Estimated offering costs and expenses				5,000,000
Preferred shares authorized for issuance (shares)													40,000,000		10,000,000
Preferred stock par value per share					$0.01										$0.01
Preferred stock, shares sold (shares)					646,295
Preferred stock, dividend rate, percentage (percentage)	8.63%
Redemption Price					$25
Proceeds from issuance of preferred stock and preference stock					13,600,000
Payments of dividends	-8,700,000	-8,500,000	-7,100,000
Gastar Exploration USA | Series B Preferred Stock
Class of Stock [Line Items]
Preferred stock par value per share							$0.01
Preferred stock, shares sold (shares)						2,140,000	2,000,000
Preferred stock, dividend rate, percentage (percentage)							10.75%
Redemption Price							$25
Exercise of option to purchase additional shares																140,000
Total net proceeds from offering						50,100,000
Preferred stock redemption price per share						$25
Aggregate common shares with option to convert from preferred shares						11.5207
Preferred stock dividends	5,800,000	847,000
Gastar Exploration USA | At The Market Sales Agreement
Class of Stock [Line Items]
Preferred stock, shares sold (shares)	4,045,000
Proceeds from issuance of preferred stock and preference stock	2,100,000
Preferred stock shares authorized to be sold in at the market sales agreement																	3,400,000
Preferred stock shares issued during current period	86,840
Cumulative net proceeds from issuance of preferred stock	78,800,000
Period after change in control to redeem preferred stock (days)	90 days
Chesapeake Energy Corporation
Class of Stock [Line Items]
Amount paid to Chesapeake								10,800,000
Repurchase of common shares								9,800,000
Repurchase of common stock (shares)								6,781,768
Chesapeake Energy Corporation | Gastar Exploration USA
Class of Stock [Line Items]
Amount paid to Chesapeake								1,000,000
Repurchase of common shares								$9,800,000
2006 Long-Term Stock Incentive Plan
Class of Stock [Line Items]
Shares reserved for issuance under LTIP									3,000,000
Shares available for future issuance (no more than) (shares)	4,561,508
Stock options
Class of Stock [Line Items]
Common shares reserved for the exercise of stock options (shares)	866,600
PBUs
Class of Stock [Line Items]
Common shares reserved for the exercise of stock options (shares)	990,658

Capital_Stock_Schedule_of_Issu

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options exercised (shares)	7,500		10,000
Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted common shares granted (shares)	601,473		2,288,179
Restricted common shares vested (shares)	1,915,242		762,682
Shares of common stock issued pursuant to PBUs vested, net of forfeitures	472,189		0
Common shares forfeited (shares)	612,612	[1]	224,500	[1]
Common shares canceled (shares)	47,398		512,862
[1]	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested and with the payment of the exercise price and estimated withholding taxes on option exercises during the period.

Equity_Compensation_Plans_Narr

Equity Compensation Plans (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividend rate utilized in the Black-Scholes Merton valuation model	0.00%
Expected Forfeitures (percentage)	25.50%	14.00%	15.50%
Unrecognized expense for outstanding awards	$2.80
Stock-based compensation expense	4.9	3.4	3.3
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life (in years)	6 years 3 months
Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)	3 years
Unrecognized expense for outstanding awards	1.6
Weighted average period for recognition for unrecognized expense	1 year 5 months 5 days
Unvested restricted shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)	2 years
Unvested restricted shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)	4 years
PBUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	1.7
Total unrecognized expense for PBUs	$1.10
2006 Long-Term Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future issuance (no more than) (shares)	4,561,508
2006 Long-Term Stock Incentive Plan | Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)	3 years
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)	2 years
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)	4 years
2006 Long-Term Stock Incentive Plan | PBUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)	3 years
Percentage settlement of targeted number of PBUs	100.00%
2006 Long-Term Stock Incentive Plan | PBUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage settlement of targeted number of PBUs	0.00%
2006 Long-Term Stock Incentive Plan | PBUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage settlement of targeted number of PBUs	200.00%

Equity_Compensation_Plans_Sche

Equity Compensation Plans (Schedule of Weighted Average Grant Date Fair Value) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value (in dollars per share)	$0		$0		$0
Intrinsic value of stock options exercised	$28	[1]	$19	[1]	$2	[1]
Grant date fair value of stock options vested	27		88		117
Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value (in dollars per share)	$5.85		$1.30		$2.09
Grant date fair value of stock options vested	$3,497		$2,725		$2,492
[1]	Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised.

Equity_Compensation_Plans_Shar

Equity Compensation Plans (Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable) (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Exercised	-7,500	-10,000
Stock options
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at beginning of period	874,100
Granted	0
Exercised	-7,500
Canceled/Expired	0
Forfeited	0
Outstanding at end of period	866,600
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Weighted-Average Exercise Price, Outstanding at beginning of period	11.68
Granted	0
Exercised	2.6
Canceled/Expired	0
Forfeited	0
Weighted-Average Exercise Price, Outstanding at end of period	11.75
Number of shares vested and exercisable	866,600
Weighted Average Exercise Price per Share	11.75
Weighted Average Remaining Contractual Term (in years)	2 years 2 months 9 days
Aggregate Intrinsic Value (in thousands)	0

Equity_Compensation_Plans_Sche1

Equity Compensation Plans (Schedule of Non-vested Options) (Details) (Stock options, USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock options
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Outstanding non-vested options beginning balance	10,000
Stock options granted during the period	0
Vested	-10,000
Forfeited	0
Outstanding non-vested options ending balance	0	10,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Outstanding non-vested options at beginning of period	$2.74
Granted	$0	$0	$0
Vested	$2.74
Forfeited	$0
Outstanding non-vested options at end of period	$0	$2.74
Weighted Average Exercise Price per Share	$0
Weighted Average Remaining Contractual Term (in years)	0 years
Aggregate Intrinsic Value (in thousands)	$0

Equity_Compensation_Plans_Rest

Equity Compensation Plans (Restricted Stock Activity) (Details) (Unvested restricted shares, USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014
Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested PBUs at December 31, 2013	3,773,081
Granted	601,473
Vested	-1,915,242
Forfeited	-47,398
Unvested PBUs at December 31, 2014	2,411,914
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Wieghted-Average Grant Date Fair Value, Outstanding at beginning of period	$1.82
Granted	$5.85
Vested	$1.83
Forfeited	$3.76
Weighted-Average Grant Date Fair Value, Outstanding at end of period	$2.79
Weighted Average Remaining Contractual Term (in years)	8 years 1 month 10 days
Aggregate Intrinsic Value (in thousands)	$5,813

Equity_Compensation_Plans_Summ

Equity Compensation Plans (Summary of PBUs) (Details) (PBUs, USD $)	12 Months Ended
	Dec. 31, 2014
PBUs
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested PBUs at December 31, 2013	1,065,734
Granted	280,171
Vested	-355,247
Forfeited	0
Unvested PBUs at December 31, 2014	990,658
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Unvested PBUs at December 31, 2013	$1.56
Granted	$7.34
Vested	$1.56
Forfeited	$0
Unvested PBUs at December 31, 2014	$3.19

Equity_Compensation_Plans_Sche2

Equity Compensation Plans (Schedule of Future Amortization of Unrecognized Compensation Cost) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
2015	$2,034
2016	663
2017	59
Total	$2,756

Interest_Expense_Schedule_of_C

Interest Expense (Schedule of Components of Interest Expense) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Interest expense:
Cash and accrued	$28,851,000		$14,130,000		$1,992,000
Amortization of deferred financing costs	3,067,000	[1],[2]	2,322,000	[1],[2]	224,000	[1],[2]
Capitalized interest	-4,347,000		-3,284,000		-1,946,000
Total interest expense	27,571,000		13,168,000		270,000
Deferred financing costs written off			1,200,000
Accretion of debt discount	$2,300,000		$716,000
[1]	The years ended DecemberB 31, 2014 and 2013 include $2.3 million and $716,000, respectively, of debt discount accretion related to the Notes.
[2]	The year ended DecemberB 31, 2013 includes $1.2 million of deferred financing costs written off as a result of the Revolving Credit Facility. For more information, see Note 4. bLong-Term Debt - Second Amended and Restated Revolving Credit Facility.b

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended			36 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2007	Jun. 07, 2013
Related Party Transaction [Line Items]
Repurchase of common shares	$0	$9,753,000	$0
Investor
Related Party Transaction [Line Items]
Common shares acquired by Chesapeake Energy Corporation (shares)				6,781,768
Chesapeake Energy Corporation
Related Party Transaction [Line Items]
Amount paid to Chesapeake					10,800,000
Repurchase of common shares					$9,800,000
Repurchase of common stock (shares)					6,781,768

Income_Taxes_Schedule_of_Incom

Income Taxes (Schedule of Income (loss) before Provision for Income Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
United States	$50,953	$51,276	($152,322)
Foreign	0	-1,934	-1,469
Total income (loss) before income taxes	$50,953	$49,342	($153,791)

Income_Taxes_Schedule_of_Compo

Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Deferred:
Federal	$0	($15,299)	$0
State	0	-743	0
Foreign	0	0	0
Income tax expense (benefit)	$0	($16,042)	$0

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Foreign tax credit carry forwards	$50,681,000	$50,681,000
Federal
Operating Loss Carryforwards [Line Items]
Federal statutory rate	35.00%
Net operating loss carryforwards	$447,000,000

Income_Taxes_Income_Tax_Reconc

Income Taxes (Income Tax Reconciliation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Contingency [Line Items]
Expected income tax provision (benefit) at statutory rate	$17,833	$11,655	($53,827)
State tax, tax effected	803	96	-2,562
Stock-based compensation expense	-1,291	605	560
Gain on acquisition of assets at fair value	0	-9,685	0
Non-deductible costs of migration from Canada to U.S.	0	95	0
Other	38	-49	15
Other changes in valuation allowance	-17,383	-38,777	55,939
Actual income tax provision	0	-16,042	0
Canada
Income Tax Contingency [Line Items]
Tax effect of Canadian tax rate differences	0	193	-125
Loss of Canadian tax attributes due to migration from Canada	$0	$19,825	$0

Income_Taxes_Schedule_of_Defer

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Deferred tax asset (liability):
Capital assets	($134,223)	($77,456)
Stock-based compensation	4,504	6,501
Net operating loss carry forwards	164,056	122,675
Foreign tax credit carry forwards	50,681	50,681
Valuation allowance	-85,018	-102,401
Net deferred tax asset	$0	$0

Earnings_Per_Share_Schedule_of

Earnings Per Share (Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]
Net income (loss) attributable to common stockholder	$26,671	$9,807	$2,016	($1,965)	($3,344)	($3,942)	$51,836	($4,586)	$36,529	$39,964	($160,868)
Weighted average common shares outstanding basic (shares)	75,994,979	60,006,903	58,702,982	58,204,532	57,433,550	57,359,357	62,398,472	63,864,527	63,270,733	60,220,115	63,538,362
Weighted average common shares outstanding diluted (shares)	78,577,762	63,399,446	61,922,874	58,204,532	57,433,550	57,359,357	63,813,423	63,864,527	66,492,589	63,618,401	63,538,362
Basic (dollars per share)	$0.35	$0.16	$0.03	($0.03)	($0.06)	($0.07)	$0.83	($0.07)	$0.58	$0.66	($2.53)
Diluted (dollars per share)	$0.34	$0.15	$0.03	($0.03)	($0.06)	($0.07)	$0.81	($0.07)	$0.55	$0.63	($2.53)
Common shares excluded from denominator as anti-dilutive (shares)									34,058	3,505	2,768,402
Unvested restricted shares
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]
Incremental shares									2,451,903	2,869,490	0
Common shares excluded from denominator as anti-dilutive (shares)									34,058	3,505	1,831,435
Stock options
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]
Incremental shares									97,491	26,095	0
Common shares excluded from denominator as anti-dilutive (shares)									0	0	936,967
PBUs
Schedule of Earnings Per Share Basic and Diluted By Common Class Including Two Class Method [Line Items]
Incremental shares									672,462	502,701	0

Commitments_And_Contingencies_1

Commitments And Contingencies (Narrative) (Details) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 17, 2010

Apr. 22, 2014

Oct. 30, 2014

Jun. 07, 2013

Jun. 30, 2014

Jun. 17, 2014

Dec. 31, 2010

Dec. 31, 2011

Aug. 07, 2013

well

MMcf

Loss Contingencies [Line Items]

Office lease expense

$649,000

$372,000

$377,000

Repurchase of common shares

0

9,753,000

0

Asset retirement obligation

5,557,000

6,063,000

6,963,000

8,275,000

Asset retirement obligation, current

82,000

633,000

Asset retirement obligation, non-current

5,475,000

5,430,000

Gastar Exploration Ltd vs US Specialty Ins Co and Axis Ins Co

Loss Contingencies [Line Items]

Litigation settlement, gross

21,200,000

Directors and officers liability coverage limit

20,000,000

Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania

Loss Contingencies [Line Items]

Number of wells drilled

3

Gross acres

3,300

Proved undeveloped well locations on lease

87,700,000

Percentage of total company proved reserves

19.00%

Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania | Surety Bond | Judicial Ruling

Loss Contingencies [Line Items]

Loss contingency, damages sought, value

800,000

Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania | Marshall County, West Virginia

Loss Contingencies [Line Items]

Gross acres

13,700

Chesapeake Energy Corporation

Loss Contingencies [Line Items]

Repurchase of common shares

9,800,000

Amount paid to Chesapeake

10,800,000

SEI Energy LLC | Capacity | Fort Beeler Processing Plant

Loss Contingencies [Line Items]

Capacity of processing plants (MMcf/day)

520

SEI Energy LLC | Capacity | Oak Grove Processing Plant

Loss Contingencies [Line Items]

Capacity of processing plants (MMcf/day)

200

Gastar Exploration USA | Gastar Exploration USA Inc v Williams Ohio Valley Midstream LLC

Loss Contingencies [Line Items]

Litigation settlement, gross

8,600,000

Damages sought in arbitration matter

612,000

Gastar Exploration USA | Chesapeake Energy Corporation

Loss Contingencies [Line Items]

Litigation settlement, gross

80,000,000

Acquisition of oil and natural gas properties

69,400,000

Repurchase of common shares

9,800,000

Amount paid to Chesapeake

$1,000,000

Gastar Exploration USA | SEI Energy LLC | Capacity

Loss Contingencies [Line Items]

Natural gas production term (years)

5 years

Gastar Exploration USA | Atinum and SEI Energy | Capacity

Loss Contingencies [Line Items]

Natural gas production term (years)

10 years

Commitments_And_Contingencies_2

Commitments And Contingencies (Schedule of Future Minimum Rental Commitments) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
2015	$640
2016	498
2017	187
2018	161
Total	$1,486

Concentration_of_Risk_and_Sign2

Concentration of Risk and Significant Customers (Schedule of Concentration Risk) (Details) (Natural gas, oil and NGLs revenues excluding realized hedge impact)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
SEI | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	50.00%		56.00%		47.00%
Sunoco | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	37.00%		16.00%		0.00%
Clearfield Appalachian | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	0.00%		8.00%		14.00%
ETC | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	0.00%		8.00%		24.00%
Appalachian Basin | Geographic Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	39.00%		65.00%		72.00%
Mid-Continent | Geographic Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	61.00%		26.00%		0.00%
Hilltop Area, East Texas | Geographic Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	0.00%	[1]	9.00%	[1]	27.00%	[1]
Powder River Basin | Geographic Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	0.00%	[2]	0.00%	[2]	1.00%	[2]
[1]	The Company's working interest in the Hilltop Area, East Texas was sold on October 2, 2013, with an effective date of January 1, 2013.
[2]	The Company's working interest in the Powder River Basin was assigned to the operator on May 3, 2012, with an effective date of January 1, 2012.

Statement_Of_Cash_Flows_Supple2

Statement Of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of capitalized amounts	$24,632	$7,341	$39
Non-cash transactions:
Capital expenditures included in accounts payable and accrued drilling costs	12,777	582	4,666
Capital expenditures included in accounts receivable	4,077	-4,077	-929
Asset retirement obligation included in oil and natural gas properties	221	-1,302	1,164
Asset retirement obligation sold/assigned to operator	-645	-4,354	-2,227
Application of advances to operators	58,326	19,755	7,441
Other	($11)	$47	($36)

Quarterly_Consolidated_Financi2

Quarterly Consolidated Financial Data - Unaudited (Details) (USD $)	3 Months Ended												12 Months Ended			0 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 07, 2013
Schedule Of Quarterly Financial Information [Line Items]
Revenues	$61,448	$41,746	$35,897	$32,327	$26,725		$18,840		$30,926		$11,264
Income from operations	37,063	20,413	12,539	8,497	5,178		1,626		13,809		-1,849		78,512	18,764	-153,528
Income (loss) before provision for income taxes	30,290	13,425	5,627	1,611	-16,406	[1]	-1,808	[1]	53,970	[1]	-2,456	[1]
NET INCOME (LOSS)	30,290	13,425	5,627	1,611	-364		-1,808		53,970		-2,456		50,953	49,342	-153,791
Dividend on preferred stock	3,619	3,618	3,611	3,576	2,980		2,134		2,134		2,130
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	26,671	9,807	2,016	-1,965	-3,344		-3,942		51,836		-4,586		36,529	39,964	-160,868
Basic (in dollars per share)	$0.35	$0.16	$0.03	($0.03)	($0.06)		($0.07)		$0.83		($0.07)		$0.58	$0.66	($2.53)
Diluted (in dollars per share)	$0.34	$0.15	$0.03	($0.03)	($0.06)		($0.07)		$0.81		($0.07)		$0.55	$0.63	($2.53)
Basic (shares)	75,994,979	60,006,903	58,702,982	58,204,532	57,433,550		57,359,357		62,398,472		63,864,527		63,270,733	60,220,115	63,538,362
Diluted (shares)	78,577,762	63,399,446	61,922,874	58,204,532	57,433,550		57,359,357		63,813,423		63,864,527		66,492,589	63,618,401	63,538,362
Gain on acquisition of assets at fair value, net of income taxes									43,700				0	27,670	0
Chesapeake Assets | Gastar Exploration USA
Schedule Of Quarterly Financial Information [Line Items]
Gain on acquisition of assets at fair value, net of income taxes																27,670
Deferred tax liability																$16,042
[1]	Income before provision for income taxes for the second quarter 2013 includes a gain on acquisition of assets at fair value of $43.7 million. Income before provision for income taxes for the fourth quarter 2013 includes adjustment to gain on acquisition of assets to reflect the deferred tax liabilities assumed of $16.0 million.

Supplemental_Oil_and_Gas_Discl2

Supplemental Oil and Gas Disclosures - Unaudited (Narrative) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Extractive Industries [Abstract]
Asset retirement costs	$2.40	$3.40	$4.80

Supplemental_Oil_and_Gas_Discl3

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties:	$1,124,367	$935,773	$671,193
Total proved properties	128,274	96,220	67,892
Total oil and natural gas properties	1,252,641	1,031,993	739,085
Accumulated depreciation, depletion and amortization	-223,555	-177,790	-145,631
Net capitalized costs	691,147	516,264	255,515
United States
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties:	1,124,367	935,773	671,193
Total proved properties	128,274	96,220	67,892
Impairment of proved oil and natural gas properties	($337,939)	($337,939)	($337,939)

Supplemental_Oil_and_Gas_Discl4

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) (United States, USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition	$0	[1]	$189,594,000	[1]	$0	[1]
Unproved property acquisition	41,475,000	[2]	71,472,000	[2]	25,676,000	[2]
Exploration	127,384,000		36,893,000		10,041,000
Development	57,913,000		53,058,000		111,878,000
Total costs incurred	226,772,000		351,017,000		147,595,000
Downward adjustment for fair value of acquisition			-2,600,000
Adjustment for fair value of acquisition			$46,300,000
[1]	The 2013 property acquisition costs exclude a downward adjustment of $2.6 million for fair value of acquisition.
[2]	The 2013 property acquisition costs exclude $46.3 million of adjustment for fair value of acquisition.

Supplemental_Oil_and_Gas_Discl5

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Results of Operations for Oil and Gas Producing Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Oil, condensate, natural gas and NGLs sales, including commodity derivatives	$171,418	$87,755	$49,940
Production expenses	-29,735	-18,113	-13,408
Impairment of oil and natural gas properties	0	0	-150,787
Depreciation, depletion and amortization	-45,765	-32,158	-25,195
Results of producing activities	$95,918	$37,484	($139,450)
Depreciation, depletion and amortization per MBoe	12.34	9.94	11.41

Supplemental_Oil_and_Gas_Discl6

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Oil and Gas Net Production, Average Sales Price and Average Production Costs) (Details)

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Natural gas (per MMBtu):

Average Sales Price and Production Costs Per Unit of Production [Line Items]

Key natural gas and oil prices

4.35

[1]

4.24

[1]

4.1

[1]

3.99

[1]

3.67

[1]

3.61

[1]

3.44

[1]

2.95

[1]

2.76

[1]

2.83

[1]

3.15

[1]

3.73

[1]

Oil (per Bbl):

Average Sales Price and Production Costs Per Unit of Production [Line Items]

Key natural gas and oil prices

94.99

[1]

99.08

[1]

100.11

[1]

98.3

[1]

96.78

[1]

91.69

[1]

88.13

[1]

89.17

[1]

91.21

[1]

91.48

[1]

92.17

[1]

94.65

[1]

Henry Hub | Natural gas (per MMBtu):

Average Sales Price and Production Costs Per Unit of Production [Line Items]

Key natural gas and oil prices

4.35

3.67

2.76

WTI spot | Oil (per Bbl):

Average Sales Price and Production Costs Per Unit of Production [Line Items]

Key natural gas and oil prices

94.99

96.78

94.71

[1]

For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Supplemental_Oil_and_Gas_Discl7

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	MBoe		MBoe		MBoe
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period, equivalents	54,634,000	[1],[2]	30,152,000	[1],[2]	19,953,000	[1],[2]
Extensions and discoveries	42,810,000	[1],[2],[3]	15,483,000	[1],[2],[4]	14,861,000	[1],[2],[5]
Revisions of previous estimates	-8,574,000	[1],[2]	-1,729,000	[1],[2]	-2,230,000	[1],[2]
Production	-3,708,000	[1],[2]	-3,237,000	[1],[2]	-2,208,000	[1],[2]
Purchases in place			14,639,000	[1],[2]	7,000	[1],[2]
Sales in place	-247,000	[1],[2]	-4,132,000	[1],[2]	-231,000	[1],[2]
Proved reserves at the end of the period. equivalents	102,063,000	[1],[2]	54,634,000	[1],[2]	30,152,000	[1],[2]
Proved developed reserves	36,789,000	[1],[2]	30,892,000	[1],[2]	21,109,000	[1],[2]
Proved undeveloped reserves	65,274,000	[1],[2]	23,742,000	[1],[2]	9,042,000	[1],[2]
Total	102,063,000	[1],[2]	54,634,000	[1],[2]	30,151,000	[1],[2]
Percentage of extensions and discoveries from successful drilling results in Marcellus Shale	69.00%		74.00%
Natural Gas
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period	180,710	[6]	131,010	[6]	91,652	[6]
Extensions and discoveries	121,672	[3],[6]	52,750	[4],[6]	57,835	[5],[6]
Revisions of previous estimates	2,465	[6]	-8,114	[6]	-6,518	[6]
Production	-11,598	[6]	-13,366	[6]	-10,564	[6]
Purchases in place			26,961	[6]	0	[6]
Sales in place	-1,314	[6]	-24,759	[6]	-1,395	[6]
Proved reserves as of the end of the period	287,005	[6]	180,710	[6]	131,010	[6]
Proved developed reserves	114,564	[6]	114,195	[6]	95,602	[6]
Proved undeveloped reserves	172,441	[6]	66,515	[6]	35,408	[6]
Total	287,005	[6]	180,710	[6]	131,010	[6]
Natural Gas Liquids
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period	9,798,000	[7]	4,922,000	[7]	2,757,000	[7]
Extensions and discoveries	9,394,000	[3],[7]	2,306,000	[4],[7]	2,783,000	[5],[7]
Revisions of previous estimates	-7,205,000	[7]	-714,000	[7]	-348,000	[7]
Production	-800,000	[7]	-494,000	[7]	-270,000	[7]
Purchases in place			2,350,000	[7]	0	[7]
Sales in place	-4,000	[7]	0	[7]	0	[7]
Proved reserves as of the end of the period	25,593,000	[7]	9,798,000	[7]	4,922,000	[7]
Proved developed reserves	10,726,000	[7]	6,025,000	[7]	3,216,000	[7]
Proved undeveloped reserves	14,867,000	[7]	3,773,000	[7]	1,706,000	[7]
Total	25,593,000	[7]	9,798,000	[7]	4,922,000	[7]
Oil
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period	14,718,000	[7]	3,394,000	[7]	1,921,000	[7]
Extensions and discoveries	13,137,000	[3],[7]	4,385,000	[4],[7]	2,439,000	[5],[7]
Revisions of previous estimates	-1,780,000	[7]	337,000	[7]	-796,000	[7]
Production	-975,000	[7]	-515,000	[7]	-177,000	[7]
Purchases in place			7,796,000	[7]	7,000	[7]
Sales in place	-24,000	[7]	-5,000	[7]	0	[7]
Proved reserves as of the end of the period	28,636,000	[7]	14,718,000	[7]	3,394,000	[7]
Proved developed reserves	6,968,000	[7]	5,834,000	[7]	1,959,000	[7]
Proved undeveloped reserves	21,668,000	[7]	8,884,000	[7]	1,435,000	[7]
Total	28,636,000	[7]	14,718,000	[7]	3,394,000	[7]
[1]	Thousand barrels of oil, condensate or NGLs equivalent.
[2]	Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
[3]	Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
[4]	Of the 2013 extensions and discoveries, 74% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2013 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
[5]	The 2012 extensions and discoveries were the result of the extension of proved acreage of the previously discovered Marcellus Shale reservoir through additional drilling during the years subsequent to initial discovery.
[6]	Million cubic feet or million cubic feet equivalent, as applicable
[7]	Thousand barrels

Supplemental_Oil_and_Gas_Discl8

Supplemental Oil and Gas Disclosures - Unaudited (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves) (Details) (United States, USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$3,855,227	$2,103,023	$672,142
Future production costs	-1,048,554	-588,568	-167,864
Future development costs	-611,602	-296,666	-83,697
Future income taxes	-486,593	-215,502	0	[1]
Future net cash flows	1,708,478	1,002,287	420,581
10% annual discount for estimated timing of cash flows	-891,739	-486,458	-213,772
Standardized measure of discounted future cash flows	$816,739	$515,829	$206,809		$212,783
[1]	No future taxes payable has been included in the determination of discounted future net cash flows for 2012 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows.

Supplemental_Oil_and_Gas_Discl9

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) (United States, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
United States
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning of period	$515,829	$206,809	$212,783
Extensions and discoveries, less related costs	369,806	196,448	112,390
Sale of natural gas and oil, net of production costs	-122,114	-74,394	-29,110
Purchases of reserves in place		247,208	64
Sales of reserves in place	-1,475	-9,063	-216
Revisions of previous quantity estimates	101,044	6,191	-30,959
Net change in income tax	-95,245	-76,701	4,334
Net change in prices and production costs	59,786	79,820	-98,589
Accretion of discount	-3,996	1,211	1,152
Development costs incurred	37,461	23,567	19,702
Net change in estimated future development costs	-1,277	-97,461	2,518
Change in production rates (timing) and other	-43,081	12,194	12,740
End of period	$816,739	$515,829	$206,809