Gastar Exploration (GST) 10-Q 7 May 15 2015 Q1 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	3 Months Ended
	Mar. 31, 2015	4-May-15
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Entity Registrant Name	Gastar Exploration Inc.
Entity Central Index Key	1431372
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		81,145,775

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$12,143	$11,008
Accounts receivable, net of allowance for doubtful accounts of $0, respectively	18,187	30,841
Commodity derivative contracts	18,815	19,687
Prepaid expenses	1,808	2,083
Total current assets	50,953	63,619
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	120,341	128,274
Proved properties	1,174,581	1,124,367
Total oil and natural gas properties	1,294,922	1,252,641
Furniture and equipment	3,013	3,010
Total property, plant and equipment	1,297,935	1,255,651
Accumulated depreciation, depletion and amortization	-577,822	-563,351
Total property, plant and equipment, net	720,113	692,300
OTHER ASSETS:
Commodity derivative contracts	13,404	7,815
Deferred charges, net	2,682	2,586
Advances to operators and other assets	2,770	9,474
Total other assets	18,856	19,875
TOTAL ASSETS	789,922	775,794
CURRENT LIABILITIES:
Accounts payable	19,780	28,843
Revenue payable	8,258	9,122
Accrued interest	10,550	3,528
Accrued drilling and operating costs	6,598	5,977
Advances from non-operators	1,025	1,820
Commodity derivative contracts	56	0
Commodity derivative premium payable	2,472	2,481
Asset retirement obligation	84	82
Other accrued liabilities	1,975	3,175
Total current liabilities	50,798	55,028
LONG-TERM LIABILITIES:
Long-term debt	380,916	360,303
Commodity derivative contracts	340	0
Commodity derivative premium payable	4,809	4,702
Asset retirement obligation	5,676	5,475
Total long-term liabilities	391,741	370,480
Commitments and contingencies (Note 11)
STOCKHOLDERS’ EQUITY:
Common stock	78	78
Additional paid-in capital	568,541	568,440
Accumulated deficit	-221,298	-218,294
Total stockholders’ equity	347,383	350,286
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	789,922	775,794
Series A Preferred Stock
STOCKHOLDERS’ EQUITY:
Preferred stock	41	41
Series B Preferred Stock
STOCKHOLDERS’ EQUITY:
Preferred stock	$21	$21

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, except Share data, unless otherwise specified
Accounts receivable, net of allowance for doubtful accounts	$0	$0
Preferred stock, shares authorized	40,000,000	40,000,000
Preferred stock, par value	$0.01
Liquidation Preference	$25
Common stock, par value	$0.00	$0.00
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	80,145,775	78,632,810
Common stock, shares outstanding	80,145,775	78,632,810
Series A Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares issued	4,045,000	4,045,000
Preferred stock, shares outstanding	4,045,000	4,045,000
Liquidation Preference	$25	$25
Series B Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares issued	2,140,000	2,140,000
Preferred stock, shares outstanding	2,140,000	2,140,000
Liquidation Preference	$25	$25

Condensed_Consolidated_Stateme

Condensed Consolidated Statements Of Operations (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
REVENUES:
Oil and condensate	$15,353	$16,778
Natural gas	6,700	15,419
NGLs	2,096	6,644
Total oil, condensate, natural gas and NGLs revenues	24,149	38,841
Gain (loss) on commodity derivatives contracts	10,223	-6,514
Total revenues	34,372	32,327
EXPENSES:
Production taxes	840	1,894
Lease operating expenses	6,019	4,044
Transportation, treating and gathering	497	625
Depreciation, depletion and amortization	14,471	12,382
Accretion of asset retirement obligation	125	122
General and administrative expense	4,248	4,763
Total expenses	26,200	23,830
INCOME FROM OPERATIONS	8,172	8,497
OTHER INCOME (EXPENSE):
Interest expense	-7,561	-6,891
Investment income and other	3	7
Foreign transaction loss	0	-2
INCOME BEFORE PROVISION FOR INCOME TAXES	614	1,611
Provision for income taxes	0	0
NET INCOME	614	1,611
Dividends on preferred stock	-3,618	-3,576
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	($3,004)	($1,965)
NET LOSS PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic (in dollars per share)	($0.04)	($0.03)
Diluted (in dollars per share)	($0.04)	($0.03)
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic (shares)	77,114,826	58,204,532
Diluted (shares)	77,114,826	58,204,532

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements Of Cash Flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$614		$1,611
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	14,471		12,382
Stock-based compensation	1,526		1,533
Total (gain) loss on commodity derivatives contracts	-10,223		6,514
Cash settlements of matured commodity derivatives contracts, net	5,277		-3,015
Cash premiums paid for commodity derivatives contracts	0		-71
Amortization of deferred financing costs	822	[1]	733	[1]
Accretion of asset retirement obligation	125		122
Settlement of asset retirement obligation	0		-257
Changes in operating assets and liabilities:
Accounts receivable	14,279		-750
Prepaid expenses	275		81
Accounts payable and accrued liabilities	5,957		4,169
Net cash provided by operating activities	33,123		23,052
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties	-46,121		-25,812
Advances to operators	-1,753		-5,001
Acquisition of oil and natural gas properties - refund	0		4,209
Proceeds from (payment related to) sale of oil and natural gas properties	2,008		-341
(Payments to) proceeds from non-operators	-795		4,930
Purchase of furniture and equipment	-3		-148
Net cash used in investing activities	-46,664		-22,163
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	25,000		0
Repayment of revolving credit facility	-5,000		0
Proceeds from issuance of preferred stock, net of issuance costs	0		886
Dividends on preferred stock	-3,618		-3,576
Deferred financing charges	-281		-135
Tax withholding related to restricted stock and PBU vestings	-1,425		-3,544
Net cash provided by (used in) financing activities	14,676		-6,369
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,135		-5,480
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	11,008		32,393
CASH AND CASH EQUIVALENTS, END OF PERIOD	$12,143		$26,913
[1]	The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

Description_Of_Business

Description Of Business	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of business	Description of Business
	Gastar Exploration Inc. (the “Company” or “Gastar,” and before January 31, 2014, “Gastar USA”) 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 and completed its first successful dry gas Utica Shale/Point Pleasant well on its acreage.
	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. 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 and 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	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	Summary of Significant Accounting Policies
	The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2014 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material item included in those notes has changed except as a result of normal transactions in the interim or as disclosed within this report.
	The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K.
	The preparation of 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 revenues and expenses during the reporting period. 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.
	The unaudited interim condensed consolidated financial statements of the Company include the consolidated accounts of all of its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation.
	Certain reclassifications of prior year balances have been made to conform to the current year presentation; these reclassifications have no impact on net income (loss).
	The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. 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 condensed consolidated financial statements, as appropriate.
	Recent Accounting Developments
	The following recently issued accounting pronouncement may impact the Company in future periods:
	Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.
	Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.
	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. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018. The proposal will be subject to the FASB's due process requirement, which includes a period for public comments. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

Property_Plant_And_Equipment

Property, Plant And Equipment	3 Months Ended
	Mar. 31, 2015
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 and Oklahoma.
	The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:
		March 31, 2015		December 31, 2014
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	17,468	$	29,193
	Acreage acquisition costs	94,079		91,362
	Capitalized interest	8,794		7,719
	Total unproved properties excluded from amortization	$	120,341	$	128,274
	For the three months ended March 31, 2015, 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 $35,000 of unproved properties to proved properties for the three months ended March 31, 2015 related to acreage in Marcellus East.
	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 the Company's 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 with respect to valuing future net cash flows from proved reserves for this purpose. 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 pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:
		2015
		Total Impairment		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)			$	3.88
	West Texas Intermediate oil price (per Bbl)(1)			$	82.72
	Impairment recorded (pre-tax) (in thousands)	$	—	$	—
		2014
		Total Impairment		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)			$	3.99
	West Texas Intermediate oil price (per Bbl)(1)			$	98.3
	Impairment recorded (pre-tax) (in thousands)	$	—	$	—
	_________________________________
	-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.
	Mid-Continent Divestiture
	On May 1, 2015, the Company entered into a purchase and sale agreement with an undisclosed private third party to sell certain non-core assets comprised of 38 gross (16.7 net) wells producing approximately net 170 Boe/d (41% oil) for the three months ended March 31, 2015 and approximately 29,300 gross (19,000 net) acres in Kingfisher County, Oklahoma for approximately $46.2 million, subject to customary closing adjustments. The transaction is expected to close on or before June 22, 2015, with an effective date of April 1, 2015. The sale will be reflected as a reduction to the full cost pool and the Company does not anticipate recording a gain or loss related to the divestiture as it is not significant to the full cost pool.
	Atinum Joint Venture
	In September 2010, the Company entered into a joint venture (the “Atinum Joint Venture”) pursuant to which the Company ultimately assigned to an affiliate of Atinum Partners Co., Ltd. (“Atinum”), for total consideration of $70.0 million, a 50% working interest in certain undeveloped acreage and wells. Effective 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, the Company 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 the Company 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.
	The Atinum Joint Venture pursued an initial three-year development program that called for the partners to drill a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, Atinum and the Company agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 gross wells to 51 gross wells. At March 31, 2015, 70 gross operated horizontal Marcellus Shale wells and one gross operated horizontal Utica Shale/Point Pleasant well were capable of production under the Atinum Joint Venture. The Atinum Joint Venture Agreement expires on November 1, 2015.

LongTerm_Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2015
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 oil and natural gas 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 net 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 under 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 redeterminations are scheduled semi-annually in May and November of each calendar year. The Company and its lenders may request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. At March 31, 2015, the Revolving Credit Facility had a borrowing base of $200.0 million, with $65.0 million borrowings outstanding and availability of $135.0 million. The next regularly scheduled redetermination 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 March 31, 2015, 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 semi-annually in arrears on May 15 and November 15 of each year. 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' 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, consolidate 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.
	At March 31, 2015, the Notes reflected a balance of $315.9 million, net of unamortized discounts of $9.1 million, on the condensed consolidated balance sheets.

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2015
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 or estimated market data based on area transactions, which are Level 3 inputs. For the three months ended March 31, 2015, 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 $35,000 of unproved properties to proved properties for the three months ended March 31, 2015 related to acreage in Marcellus East. For the three months ended March 31, 2014, management's evaluation of unproved properties resulted in an impairment of $194,000 related to Marcellus East. As no other fair value measurements are required to be recognized on a non-recurring basis at March 31, 2015, no additional disclosures are provided at March 31, 2015.
	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 natural gas, oil 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 2015 and 2014 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 March 31, 2015 and December 31, 2014:
		Fair value as of March 31, 2015
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	12,143		$	—		$	—		$	12,143
	Commodity derivative contracts	—			—			32,219			32,219
	Liabilities:
	Commodity derivative contracts	—			—			(396		)	(396		)
	Total	$	12,143		$	—		$	31,823		$	43,966
		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
	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2015 and 2014. 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 March 31, 2015 and 2014.
		Three Months Ended March 31,
		2015			2014
		(in thousands)
	Balance at beginning of period	$	27,502		$	3,764
	Total gains (losses) included in earnings	10,223			(6,514		)
	Purchases	866			71
	Issuances	(186		)	—
	Settlements(1)	(6,582		)	3,299
	Balance at end of period	$	31,823		$	620
	The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2015 and 2014	$	4,252		$	(3,155	)
	_________________________________
	-1	Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.
	At March 31, 2015, 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 March 31, 2015 was $371.7 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 approximates the current market rate (Level 2).
	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 6, “Derivative Instruments and Hedging Activity.”

Derivative_Instruments_and_Hed

Derivative Instruments and Hedging Activity	3 Months Ended
	Mar. 31, 2015
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 condensed consolidated statements of operations in gain (loss) on commodity derivatives contracts. For the three months ended March 31, 2015 and 2014, the Company reported a gain of $4.3 million and a loss of $3.2 million, respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts still held at March 31, 2015 and 2014.
	As of March 31, 2015, 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			48,800			$	—		$	85	$	—	$	96.5
	2015(2)		Costless collar		360			43,920			$	—		$	85	$	—	$	97.8
	2015(2)		Costless collar		150			18,300			$	—		$	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			85,400			$	—		$	90	$	70	$	—
	2015		Put spread		250			68,750			$	—		$	89	$	69	$	—
	2015		Costless three-way collar		750			206,250			$	—		$	52.5	$	40	$	62.05
	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		Costless three-way collar		450			164,700			$	—		$	57.5	$	42.5	$	80
	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		Costless three-way collar		200			73,000			$	—		$	60	$	42.5	$	85
	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 April to June 2015.
	-3	For the period July to December 2015.
	-4	For the period January to August 2018.
	As of March 31, 2015, 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		Call		Ceiling
					Daily			Notional			Fixed			(Long)		Put		(Long)		(Short)
					Volume			Volume			Price
					(in MMBtus)
	2015		Fixed price swap		400			110,000			$	4		$	—	$	—	$	—	$	—
	2015		Fixed price swap		2,500			687,500			$	4.06		$	—	$	—	$	—	$	—
	2015		Protective spread		2,600			715,000			$	4		$	—	$	3.25	$	—	$	—
	2015		Fixed price swap		5,000			1,375,000			$	3.49		$	—	$	—	$	—	$	—
	2015		Fixed price swap		2,000			550,000			$	3.53		$	—	$	3.25	$	—	$	—
	2015		Producer three-way collar		2,500			687,500			$	—		$	3.7	$	3	$	—	$	4.09
	2015		Producer three-way collar		5,000			1,375,000			$	—		$	3.77	$	3	$	—	$	4.11
	2015(1)		Producer three-way collar		2,000			428,000			$	—		$	3	$	2.25	$	—	$	3.34
	2015(1)		Fixed price swap		10,000			2,140,000			$	2.94		$	—	$	—	$	—	$	—
	2015		Basis swap(2)		2,500			687,500			$	(1.12	)	$	—	$	—	$	—	$	—
	2015		Basis swap(2)		2,500			687,500			$	(1.11	)	$	—	$	—	$	—	$	—
	2015		Basis swap(2)		2,500			687,500			$	(1.14	)	$	—	$	—	$	—	$	—
	2016		Protective spread		2,000			732,000			$	4.11		$	—	$	3.25	$	—	$	—
	2016		Producer three-way collar		2,000			732,000			$	—		$	4	$	3.25	$	—	$	4.58
	2016		Producer three-way collar		5,000			1,830,000			$	—		$	3.4	$	2.65	$	—	$	4.1
	2016		Basis swap(3)		2,500			915,000			$	(1.10	)	$	—	$	—	$	—	$	—
	2017		Short call		10,000			3,650,000			$	—		$	—	$	—	$	—	$	4.75
	_______________________________
	-1	For the period April to October 2015.
	-2	Represents basis swaps at the sales point of Dominion South.
	-3	Represents basis swaps at the sales point of TetcoM2.
	As of March 31, 2015, 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		Fixed price swap		250		68,750			$	45.61
As of March 31, 2015, 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 contain 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 April 2015 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. The following table provides information regarding the deferred put premium liabilities for the periods indicated:
	March 31, 2015				31-Dec-14
	(in thousands)
Current commodity derivative premium put payable	$	2,472			$	2,481
Long-term commodity derivative premium payable	4,809				4,702
Total unamortized put premium liabilities	$	7,281			$	7,183
	For the Three Months Ended March 31, 2015
	(in thousands)
Put premium liabilities, beginning balance	$	7,183
Amortization of put premium liabilities	(582		)
Additional put premium liabilities	680
Put premium liabilities, ending balance	$	7,281
The following table provides information regarding the amortization of the deferred put premium liabilities by year as of March 31, 2015:
	Amortization
	(in thousands)
April to December 2015	1,714
January to December 2016	3,050
January to December 2017	1,684
January to August 2018	833
Total unamortized put premium liabilities	$	7,281
Additional Disclosures about Derivative Instruments and Hedging Activities
The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:
	Fair Values of Derivative Instruments
	Derivative Assets (Liabilities)
			Fair Value
	Balance Sheet Location		March 31, 2015				December 31, 2014
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets		$	18,815			$	19,687
Commodity derivative contracts	Other assets		13,404				7,815
Commodity derivative contracts	Current liabilities		(56		)		—
Commodity derivative contracts	Long-term liabilities		(340		)		—
Total derivatives not designated as hedging instruments			$	31,823			$	27,502
			Amount of Gain (Loss)
			Recognized in Income on
			Derivatives For the Three
			Months Ended March 31,
	Location of Gain (Loss) Recognized in Income on Derivatives		2015				2014
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Gain (loss) on commodity derivatives contracts		$	10,223			$	(6,514	)
Total			$	10,223			$	(6,514	)

Capital_Stock

Capital Stock	3 Months Ended
	Mar. 31, 2015
Stockholders' Equity Note [Abstract]
Capital Stock	Capital Stock
	Preferred Stock
	The Company currently has 40,000,000 shares of preferred stock authorized for issuance under its certificate of incorporation. The Company has designated 10,000,000 shares to constitute its 8.625% Series A Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 shares to constitute its 10.75% Series B Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share.
	Series A Preferred Stock
	At March 31, 2015, there were 4,045,000 shares of the Series A Preferred Stock issued and outstanding.
	The Series A Preferred Stock ranks senior to the Company's common stock and on parity with the Series B Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series A Preferred Stock is subordinated to all of the Company’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, but may be redeemed, at the Company’s option for $25.00 per share plus any accrued and unpaid dividends.
	There is no mandatory redemption of the Series A Preferred Stock.
	The Company 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 three months ended March 31, 2015, the Company recognized dividend expense of $2.2 million for the Series A Preferred Stock.
	Series B Preferred Stock
	At March 31, 2015, there were 2,140,000 shares of the Series B Cumulative Preferred Stock issued and outstanding.
	The Series B Preferred Stock ranks senior to the Company’s common stock and on parity with the Series A 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 the Company’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 the Company’s option for $25.00 per share in cash. Following a change in ownership or control, the Company 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 the Company 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 an aggregate of 11.5207 shares of the Company’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If the Company 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.
	The Company 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 three months ended March 31, 2015, the Company recognized dividend expense of $1.4 million for the Series B Preferred Stock.
	Other Share Issuances
	The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the period indicated:
		For the Three Months Ended March 31, 2015
	Other share issuances:
	Shares of restricted common stock granted	1,421,224
	Shares of restricted common stock vested	1,274,872
	Shares of common stock issued pursuant to PBUs vested, net of forfeitures	497,636
	Shares of restricted common stock surrendered upon vesting/exercise(1)	382,238
	Shares of restricted common stock forfeited	23,657
	__________________
	-1	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.
	On June 12, 2014, the Company's stockholders approved an amendment and restatement to the Gastar Exploration Inc. Long-Term Incentive Plan (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 2,849,434 shares available for issuance under the LTIP at March 31, 2015.
	Shares Reserved
	At March 31, 2015, the Company had 866,600 common shares reserved for the exercise of stock options.

Interest_Expense

Interest Expense	3 Months Ended
	Mar. 31, 2015
Interest Expense [Abstract]
Interest Expense	Interest Expense
	The following table summarizes the components of interest expense for the periods indicated:
		For the Three Months Ended March 31,
		2015			2014
		(in thousands)
	Interest expense:
	Cash and accrued	$	7,928		$	7,134
	Amortization of deferred financing costs(1)	822			733
	Capitalized interest	(1,189		)	(976		)
	Total interest expense	$	7,561		$	6,891
	_________________________________
	-1	The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

Income_Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	For the three months ended March 31, 2015 and 2014, respectively, the Company did not recognize a current income tax benefit or provision as the Company has a full valuation allowance against assets created by net operating losses generated. The Company believes it more likely than not that the assets will not be utilized.

Earnings_Per_Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2015
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 Three Months Ended March 31,
		2015			2014
		(in thousands, except per share and share data)
	Net loss attributable to common stockholders	$	(3,004	)	$	(1,965	)
	Weighted average common shares outstanding - basic	77,114,826			58,204,532
	Incremental shares from unvested restricted shares	—			—
	Incremental shares from outstanding stock options	—			—
	Incremental shares from outstanding PBUs	—			—
	Weighted average common shares outstanding - diluted	77,114,826			58,204,532
	Net loss per share of common stock attributable to common stockholders:
	Basic	$	(0.04	)	$	(0.03	)
	Diluted	$	(0.04	)	$	(0.03	)
	Common shares excluded from denominator as anti-dilutive:
	Unvested restricted shares	450,556			119,496
	Stock options	—			—
	Unvested PBUs	373,325			—
	Total	823,881			119,496

Commitments_And_Contingencies

Commitments And Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	Commitments and Contingencies
	Litigation
	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 is $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 Fourteenth Court of Appeals, which that court denied. The insurers then sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The insurers recently filed in the Texas Supreme Court a motion for rehearing of their denied petition for review, which the court has not ruled on. If the court denies the motion, 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.
	The Company has been expensing legal 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.

Statement_Of_Cash_Flows_Supple

Statement Of Cash Flows - Supplemental Information	3 Months Ended
	Mar. 31, 2015
Supplemental Cash Flow Information [Abstract]
Statement Of Cash Flows - Supplemental Information	Statement of Cash Flows – Supplemental Information
	The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated:
		For the Three Months Ended March 31,
		2015			2014
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	(282	)	$	(697	)
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued drilling costs	$	(10,366	)	$	(299	)
	Capital expenditures included in accounts receivable	—			4,077
	Asset retirement obligation included in oil and natural gas properties	77			28
	Application of advances to operators	8,457			9,490
	Other	23			78

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Basis of Accounting	The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K.
Recent Accounting Developments	Recent Accounting Developments
	The following recently issued accounting pronouncement may impact the Company in future periods:
	Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.
	Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.
	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. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018. The proposal will be subject to the FASB's due process requirement, which includes a period for public comments. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows. The Company does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	3 Months Ended
	Mar. 31, 2015
Property, Plant and Equipment [Abstract]
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:
		March 31, 2015		December 31, 2014
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	17,468	$	29,193
	Acreage acquisition costs	94,079		91,362
	Capitalized interest	8,794		7,719
	Total unproved properties excluded from amortization	$	120,341	$	128,274
Schedule Of Relevant Assumptions Used In Ceiling Test Computations	The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:
		2015
		Total Impairment		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)			$	3.88
	West Texas Intermediate oil price (per Bbl)(1)			$	82.72
	Impairment recorded (pre-tax) (in thousands)	$	—	$	—
		2014
		Total Impairment		31-Mar
	Henry Hub natural gas price (per MMBtu)(1)			$	3.99
	West Texas Intermediate oil price (per Bbl)(1)			$	98.3
	Impairment recorded (pre-tax) (in thousands)	$	—	$	—
	_________________________________
	-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.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2015
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 March 31, 2015 and December 31, 2014:
		Fair value as of March 31, 2015
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	12,143		$	—		$	—		$	12,143
	Commodity derivative contracts	—			—			32,219			32,219
	Liabilities:
	Commodity derivative contracts	—			—			(396		)	(396		)
	Total	$	12,143		$	—		$	31,823		$	43,966
		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 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 three months ended March 31, 2015 and 2014. 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 March 31, 2015 and 2014.
		Three Months Ended March 31,
		2015			2014
		(in thousands)
	Balance at beginning of period	$	27,502		$	3,764
	Total gains (losses) included in earnings	10,223			(6,514		)
	Purchases	866			71
	Issuances	(186		)	—
	Settlements(1)	(6,582		)	3,299
	Balance at end of period	$	31,823		$	620
	The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2015 and 2014	$	4,252		$	(3,155	)
	_________________________________
	-1	Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activity (Tables)	3 Months Ended
	Mar. 31, 2015
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:
		March 31, 2015				31-Dec-14
		(in thousands)
	Current commodity derivative premium put payable	$	2,472			$	2,481
	Long-term commodity derivative premium payable	4,809				4,702
	Total unamortized put premium liabilities	$	7,281			$	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 March 31, 2015:
		Amortization
		(in thousands)
	April to December 2015	1,714
	January to December 2016	3,050
	January to December 2017	1,684
	January to August 2018	833
	Total unamortized put premium liabilities	$	7,281
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 derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:
		Fair Values of Derivative Instruments
		Derivative Assets (Liabilities)
				Fair Value
		Balance Sheet Location		March 31, 2015				December 31, 2014
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	Current assets		$	18,815			$	19,687
	Commodity derivative contracts	Other assets		13,404				7,815
	Commodity derivative contracts	Current liabilities		(56		)		—
	Commodity derivative contracts	Long-term liabilities		(340		)		—
	Total derivatives not designated as hedging instruments			$	31,823			$	27,502
				Amount of Gain (Loss)
				Recognized in Income on
				Derivatives For the Three
				Months Ended March 31,
		Location of Gain (Loss) Recognized in Income on Derivatives		2015				2014
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	Gain (loss) on commodity derivatives contracts		$	10,223			$	(6,514	)
	Total			$	10,223			$	(6,514	)
Crude Oil
Derivative [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of March 31, 2015, 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			48,800			$	—		$	85	$	—	$	96.5
	2015(2)		Costless collar		360			43,920			$	—		$	85	$	—	$	97.8
	2015(2)		Costless collar		150			18,300			$	—		$	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			85,400			$	—		$	90	$	70	$	—
	2015		Put spread		250			68,750			$	—		$	89	$	69	$	—
	2015		Costless three-way collar		750			206,250			$	—		$	52.5	$	40	$	62.05
	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		Costless three-way collar		450			164,700			$	—		$	57.5	$	42.5	$	80
	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		Costless three-way collar		200			73,000			$	—		$	60	$	42.5	$	85
	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 April to June 2015.
	-3	For the period July to December 2015.
	-4	For the period January to August 2018.
Natural Gas
Derivative [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of March 31, 2015, 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		Call		Ceiling
					Daily			Notional			Fixed			(Long)		Put		(Long)		(Short)
					Volume			Volume			Price
					(in MMBtus)
	2015		Fixed price swap		400			110,000			$	4		$	—	$	—	$	—	$	—
	2015		Fixed price swap		2,500			687,500			$	4.06		$	—	$	—	$	—	$	—
	2015		Protective spread		2,600			715,000			$	4		$	—	$	3.25	$	—	$	—
	2015		Fixed price swap		5,000			1,375,000			$	3.49		$	—	$	—	$	—	$	—
	2015		Fixed price swap		2,000			550,000			$	3.53		$	—	$	3.25	$	—	$	—
	2015		Producer three-way collar		2,500			687,500			$	—		$	3.7	$	3	$	—	$	4.09
	2015		Producer three-way collar		5,000			1,375,000			$	—		$	3.77	$	3	$	—	$	4.11
	2015(1)		Producer three-way collar		2,000			428,000			$	—		$	3	$	2.25	$	—	$	3.34
	2015(1)		Fixed price swap		10,000			2,140,000			$	2.94		$	—	$	—	$	—	$	—
	2015		Basis swap(2)		2,500			687,500			$	(1.12	)	$	—	$	—	$	—	$	—
	2015		Basis swap(2)		2,500			687,500			$	(1.11	)	$	—	$	—	$	—	$	—
	2015		Basis swap(2)		2,500			687,500			$	(1.14	)	$	—	$	—	$	—	$	—
	2016		Protective spread		2,000			732,000			$	4.11		$	—	$	3.25	$	—	$	—
	2016		Producer three-way collar		2,000			732,000			$	—		$	4	$	3.25	$	—	$	4.58
	2016		Producer three-way collar		5,000			1,830,000			$	—		$	3.4	$	2.65	$	—	$	4.1
	2016		Basis swap(3)		2,500			915,000			$	(1.10	)	$	—	$	—	$	—	$	—
	2017		Short call		10,000			3,650,000			$	—		$	—	$	—	$	—	$	4.75
	_______________________________
	-1	For the period April to October 2015.
	-2	Represents basis swaps at the sales point of Dominion South.
	-3	Represents basis swaps at the sales point of TetcoM2.
Natural Gas Liquids
Derivative [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of March 31, 2015, 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		Fixed price swap		250		68,750			$	45.61

Capital_Stock_Tables

Capital Stock (Tables)	3 Months Ended
	Mar. 31, 2015
Stockholders' Equity Note [Abstract]
Schedule of Issuances And Forfeitures Of Common Shares	The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the period indicated:
		For the Three Months Ended March 31, 2015
	Other share issuances:
	Shares of restricted common stock granted	1,421,224
	Shares of restricted common stock vested	1,274,872
	Shares of common stock issued pursuant to PBUs vested, net of forfeitures	497,636
	Shares of restricted common stock surrendered upon vesting/exercise(1)	382,238
	Shares of restricted common stock forfeited	23,657
	__________________
	-1	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

Interest_Expense_Tables

Interest Expense (Tables)	3 Months Ended
	Mar. 31, 2015
Interest Expense [Abstract]
Schedule Of Components Of Interest Expense	The following table summarizes the components of interest expense for the periods indicated:
		For the Three Months Ended March 31,
		2015			2014
		(in thousands)
	Interest expense:
	Cash and accrued	$	7,928		$	7,134
	Amortization of deferred financing costs(1)	822			733
	Capitalized interest	(1,189		)	(976		)
	Total interest expense	$	7,561		$	6,891
	_________________________________
	-1	The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted
		For the Three Months Ended March 31,
		2015			2014
		(in thousands, except per share and share data)
	Net loss attributable to common stockholders	$	(3,004	)	$	(1,965	)
	Weighted average common shares outstanding - basic	77,114,826			58,204,532
	Incremental shares from unvested restricted shares	—			—
	Incremental shares from outstanding stock options	—			—
	Incremental shares from outstanding PBUs	—			—
	Weighted average common shares outstanding - diluted	77,114,826			58,204,532
	Net loss per share of common stock attributable to common stockholders:
	Basic	$	(0.04	)	$	(0.03	)
	Diluted	$	(0.04	)	$	(0.03	)
	Common shares excluded from denominator as anti-dilutive:
	Unvested restricted shares	450,556			119,496
	Stock options	—			—
	Unvested PBUs	373,325			—
	Total	823,881			119,496

Statement_Of_Cash_Flows_Supple1

Statement Of Cash Flows - Supplemental Information (Tables)	3 Months Ended
	Mar. 31, 2015
Supplemental Cash Flow Information [Abstract]
Statement Of Cash Flows Supplemental Information	The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated:
		For the Three Months Ended March 31,
		2015			2014
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	(282	)	$	(697	)
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued drilling costs	$	(10,366	)	$	(299	)
	Capital expenditures included in accounts receivable	—			4,077
	Asset retirement obligation included in oil and natural gas properties	77			28
	Application of advances to operators	8,457			9,490
	Other	23			78

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Unproved properties, excluded from amortization:
Drilling in progress costs	$17,468	$29,193
Acreage acquisition costs	94,079	91,362
Capitalized interest	8,794	7,719
Total unproved properties excluded from amortization	$120,341	$128,274

Property_Plant_And_Equipment_N

Property, Plant And Equipment (Narrative) (Details) (USD $)	3 Months Ended	1 Months Ended	0 Months Ended
	Mar. 31, 2015	Sep. 30, 2010	1-May-15
			Boe
			well
			acre
Property, Plant and Equipment [Line Items]
Amount reclassified from unproved to proved properties	$35,000
Gastar Exploration USA | Atinum Joint Venture
Property, Plant and Equipment [Line Items]
Adjusted purchase price		70,000,000
Working interest in wells (percentage)		50.00%
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%
Term of development program	3 years
Gastar Exploration USA | Atinum Joint Venture | Marcellus Shale
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells)	70
Gastar Exploration USA | Atinum Joint Venture | Utica Shale
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells)	1
Gastar Exploration USA | Atinum Joint Venture | Maximum
Property, Plant and Equipment [Line Items]
Total wells to be drilled (wells)	60
Required exploratory wells drilled net productive to be drilled in current fiscal year (wells)	51
Subsequent Event | Mid Continent Divestiture
Property, Plant and Equipment [Line Items]
Gross wells			38
Net wells			16.7
Production of wells (Boe/d)			170
Percentage oil			41.00%
Gross acres (acres)			29,300
Net acres (acres)			19,000
Total consideration			$46,200,000

Property_Plant_And_Equipment_A

Property, Plant And Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Impairment recorded (pre-tax) (in thousands)	$0		$0
Henry Hub natural gas price (per MMBtu)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe	3.88	[1]	3.99	[1]
West Texas Intermediate oil price (per Bbl)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe	82.72	[1]	98.3	[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.

LongTerm_Debt_Narrative_Detail

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

3 Months Ended

0 Months Ended

Mar. 31, 2015

Jun. 07, 2013

15-May-13

Dec. 31, 2014

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

Nov. 15, 2013

Line of Credit Facility [Line Items]

Long-term debt

380,916,000

$360,303,000

Second Amended and Restated Revolving Credit Facility

Line of Credit Facility [Line Items]

Revolving credit facility borrowing base

200,000,000

50,000,000

200,000,000

145,000,000

Borrowings outstanding

65,000,000

Borrowing availability

135,000,000

Increase in adjusted consolidated net tangibles assets

17.50%

Second Amended and Restated Revolving Credit Facility | 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 Secured Notes Due 2018 | Senior Secured Notes

Line of Credit Facility [Line Items]

Long-term debt

315,900,000

Unamortized discounts

9,100,000

Senior Secured Notes Due 2018 | Senior Secured Notes | 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

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 | Each quarter thereafter

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]

Interest rate description

federal funds rate plus

Applicable interest margin (percentage)

0.50%

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

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

1.00%

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

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

1.00%

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

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

2.00%

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

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

2.00%

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

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

3.00%

Gastar Exploration USA | Senior Secured Notes Due 2018 | Senior Secured Notes

Line of Credit Facility [Line Items]

Aggregate principal amount

$325,000,000

Interest rate

8.63%

8.63%

Percentage of aggregate principal amount

101.00%

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount reclassified from unproved to proved properties	$35,000
Impairment of unproved properties		194,000
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of long-term debt	$371,700,000

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) (Fair Value, Measurements, Recurring, USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	$32,219	$27,502
Liabilities:
Liabilities, Commodity derivative contracts	-396	0
Total	43,966	38,510
Level 1
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	0	0
Liabilities:
Liabilities, Commodity derivative contracts	0	0
Total	12,143	11,008
Level 2
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	0	0
Liabilities:
Liabilities, Commodity derivative contracts	0	0
Total	0	0
Level 3
Derivative Assets [Abstract]
Assets, Commodity derivative contracts	32,219	27,502
Liabilities:
Liabilities, Commodity derivative contracts	-396	0
Total	31,823	27,502
Cash and Cash Equivalents
Derivative Assets [Abstract]
Cash and cash equivalents	12,143	11,008
Cash and Cash Equivalents | Level 1
Derivative Assets [Abstract]
Cash and cash equivalents	12,143	11,008
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

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) (Level 3, Commodity, Fair Value, Measurements, Recurring, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$27,502		$3,764
Total gains (losses) included in earnings	10,223		-6,514
Purchases	866		71
Issuances	-186		0
Settlements	-6,582	[1]	3,299	[1]
Balance at end of period	31,823		620
Gain (loss) on commodity derivatives contracts
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2015 and 2014	$4,252		($3,155)
[1]	Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activity (Narrative) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of commodity derivative contracts	$4,252	($3,155)

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	3 Months Ended
	Mar. 31, 2015
	bbl
Costless collar | Crude Oil | Costless Collar 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	48,800	[2]
Floor (Long) (Price per MMBtu)	85	[2]
Ceiling (Short) (Price per MMBtu)	96.5	[2]
Costless collar | Crude Oil | Costless Collar 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	360	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	43,920	[2]
Floor (Long) (Price per MMBtu)	85	[2]
Ceiling (Short) (Price per MMBtu)	97.8	[2]
Costless collar | Crude Oil | Costless Collar 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	150	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	18,300	[2]
Floor (Long) (Price per MMBtu)	85	[2]
Ceiling (Short) (Price per MMBtu)	96.25	[2]
Costless three-way collar | Crude Oil | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400	[1],[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]
Costless three-way collar | Crude Oil | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	275	[1]
Total of Notional Volume (MMBtu's or Bbls)	100,600
Floor (Long) (Price per MMBtu)	85
Short Put (Price per MMBtu)	65
Ceiling (Short) (Price per MMBtu)	95.1
Costless three-way collar | Crude Oil | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	280	[1]
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
Costless three-way collar | Crude Oil | Costless Three Way Collar 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	325	[1],[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 | Crude Oil | Costless Three Way Collar 2 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	330	[1]
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 | Crude Oil | Costless Three Way Collar 2 | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	242	[1]
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
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	50	[1],[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]
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 3 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	450	[1]
Total of Notional Volume (MMBtu's or Bbls)	164,700
Floor (Long) (Price per MMBtu)	57.5
Short Put (Price per MMBtu)	42.5
Ceiling (Short) (Price per MMBtu)	80
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 3 | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	200	[1]
Total of Notional Volume (MMBtu's or Bbls)	73,000
Floor (Long) (Price per MMBtu)	60
Short Put (Price per MMBtu)	42.5
Ceiling (Short) (Price per MMBtu)	85
Costless three-way collar | Crude Oil | Cost Less Three Way Collar 4 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	750	[1]
Total of Notional Volume (MMBtu's or Bbls)	206,250
Floor (Long) (Price per MMBtu)	52.5
Short Put (Price per MMBtu)	40
Ceiling (Short) (Price per MMBtu)	62.05
Put spread | Crude Oil | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	500	[1]
Total of Notional Volume (MMBtu's or Bbls)	182,500
Floor (Long) (Price per MMBtu)	82
Short Put (Price per MMBtu)	62
Put spread | Crude Oil | 2018
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	425	[1],[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]
Put spread | Crude Oil | Put Spread 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	700	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	85,400	[2]
Floor (Long) (Price per MMBtu)	90	[2]
Short Put (Price per MMBtu)	70	[2]
Put spread | Crude Oil | Put Spread 1 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	550	[1]
Total of Notional Volume (MMBtu's or Bbls)	201,300
Floor (Long) (Price per MMBtu)	85
Short Put (Price per MMBtu)	65
Put spread | Crude Oil | Put Spread 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	250	[1]
Total of Notional Volume (MMBtu's or Bbls)	68,750
Floor (Long) (Price per MMBtu)	89
Short Put (Price per MMBtu)	69
Put spread | Crude Oil | Put Spread 2 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	300	[1]
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 | Crude Oil | Put Spread 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	600	[1],[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]
Fixed price swap | Natural Gas | Fixed Price Swap 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400
Total of Notional Volume (MMBtu's or Bbls)	110,000
Base Fixed Price (Price per MMBtu or Bbl)	4
Fixed price swap | Natural Gas | Fixed Price Swap 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	687,500
Base Fixed Price (Price per MMBtu or Bbl)	4.06
Fixed price swap | Natural Gas | Fixed Price Swap 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	1,375,000
Base Fixed Price (Price per MMBtu or Bbl)	3.49
Fixed price swap | Natural Gas | Fixed Price Swap 4 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	550,000
Base Fixed Price (Price per MMBtu or Bbl)	3.53
Short Put (Price per MMBtu)	3.25
Fixed price swap | Natural Gas | Fixed Price Swap 5 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000	[5]
Total of Notional Volume (MMBtu's or Bbls)	2,140,000	[5]
Base Fixed Price (Price per MMBtu or Bbl)	2.94	[5]
Fixed price swap | Natural Gas Liquids | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	250
Total of Notional Volume (MMBtu's or Bbls)	68,750
Base Fixed Price (Price per MMBtu or Bbl)	45.61
Protective spread | Natural Gas | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,600
Total of Notional Volume (MMBtu's or Bbls)	715,000
Base Fixed Price (Price per MMBtu or Bbl)	4
Short Put (Price per MMBtu)	3.25
Protective spread | Natural Gas | Protective Spread 3 | 2016
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
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	687,500
Floor (Long) (Price per MMBtu)	3.7
Short Put (Price per MMBtu)	3
Ceiling (Short) (Price per MMBtu)	4.09
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	1,375,000
Floor (Long) (Price per MMBtu)	3.77
Short Put (Price per MMBtu)	3
Ceiling (Short) (Price per MMBtu)	4.11
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000	[5]
Total of Notional Volume (MMBtu's or Bbls)	428,000	[5]
Floor (Long) (Price per MMBtu)	3	[5]
Short Put (Price per MMBtu)	2.25	[5]
Ceiling (Short) (Price per MMBtu)	3.34	[5]
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 4 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	732,000
Floor (Long) (Price per MMBtu)	4
Short Put (Price per MMBtu)	3.25
Ceiling (Short) (Price per MMBtu)	4.58
Producer Three Way Collar | Natural Gas | Producer Three Way Collar 5 | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	1,830,000
Floor (Long) (Price per MMBtu)	3.4
Short Put (Price per MMBtu)	2.65
Ceiling (Short) (Price per MMBtu)	4.1
Basis Swap | Natural Gas | 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[6]
Total of Notional Volume (MMBtu's or Bbls)	915,000	[6]
Base Fixed Price (Price per MMBtu or Bbl)	-1.1	[6]
Basis Swap | Natural Gas | Basis Swap 1 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	687,500	[7]
Base Fixed Price (Price per MMBtu or Bbl)	-1.12	[7]
Basis Swap | Natural Gas | Basis Swap 2 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	687,500	[7]
Base Fixed Price (Price per MMBtu or Bbl)	-1.11	[7]
Basis Swap | Natural Gas | Basis Points 3 | 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtu's or Bbls)	687,500	[7]
Base Fixed Price (Price per MMBtu or Bbl)	-1.14	[7]
Short call | Natural Gas | 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000
Total of Notional Volume (MMBtu's or Bbls)	3,650,000
Ceiling (Short) (Price per MMBtu)	4.75
[1]	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
[2]	For the period April to June 2015.
[3]	For the period July to December 2015.
[4]	For the period January to August 2018.
[5]	For the period April to October 2015.
[6]	Represents basis swaps at the sales point of TetcoM2.
[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 Liabilities (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current commodity derivative premium put payable	$2,472	$2,481
Long-term commodity derivative premium payable	4,809	4,702
Total unamortized put premium liabilities	$7,281	$7,183

Derivative_Instruments_and_Hed5

Derivative Instruments and Hedging Activity (Schedule of Deferred Put Premium Liability) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
Put Premium Liabilities [Roll Forward]
Put premium liabilities, beginning balance	$7,183
Amortization of put premium liabilities	-582
Additional put premium liabilities	680
Put premium liabilities, ending balance	$7,281

Derivative_Instruments_and_Hed6

Derivative Instruments and Hedging Activity (Schedule of Future Amortization of Put Premium) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
April to December 2015	$1,714
January to December 2016	3,050
January to December 2017	1,684
January to August 2018	833
Total unamortized put premium liabilities	$7,281	$7,183

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) (Derivatives not designated as hedging instruments, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Total derivatives not designated as hedging instruments	$31,823		$27,502
Gain (loss) on commodity derivatives contracts	10,223	-6,514
Gain (loss) on commodity derivatives contracts
Derivatives, Fair Value [Line Items]
Gain (loss) on commodity derivatives contracts	10,223	-6,514
Current assets
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	18,815		19,687
Other assets
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	13,404		7,815
Current liabilities
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	-56		0
Long-term liabilities
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	($340)		$0

Capital_Stock_Narrative_Detail

Capital Stock (Narrative) (Details) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Apr. 24, 2014	Dec. 31, 2014
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)	40,000,000			40,000,000
Preferred stock par value per share	$0.01
Liquidation Preference (per share)	$25
Dividends on preferred stock	($3,618,000)	($3,576,000)
Common shares reserved for the exercise of stock options (shares)	866,600
Parent's 2006 Long-Term Stock Incentive Plan
Class of Stock [Line Items]
Increase in the number of share reserved for issuance			3,000,000
Common shares reserved for the exercise of stock options (shares)	2,849,434
Series A Preferred Stock
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)	10,000,000			10,000,000
Preferred stock, dividend rate, percentage (percentage)	8.63%
Preferred stock par value per share	$0.01			0.01
Liquidation Preference (per share)	$25			25
Preferred stock, shares issued	4,045,000			4,045,000
Preferred stock, shares outstanding	4,045,000			4,045,000
Dividends on preferred stock	-2,200,000
Series B Preferred Stock
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)	10,000,000			10,000,000
Preferred stock, dividend rate, percentage (percentage)	10.75%
Preferred stock par value per share	$0.01			0.01
Liquidation Preference (per share)	$25			25
Preferred stock, shares issued	2,140,000			2,140,000
Preferred stock, shares outstanding	2,140,000			2,140,000
Preferred stock redemption price per share	$25
Option to convert shares of Series B Preferred Stock	11.5207
Recognized dividend expense	$1,400,000

Capital_Stock_Schedule_of_Issu

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock issued pursuant to PBUs vested, net of forfeitures	497,636
Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of restricted common stock granted	1,421,224
Shares of restricted common stock vested	1,274,872
Shares of restricted common stock surrendered upon vesting/exercise	382,238	[1]
Shares of restricted common stock forfeited	23,657
[1]	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

Interest_Expense_Schedule_of_C

Interest Expense (Schedule of Components of Interest Expense) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Interest Expense [Abstract]
Cash and accrued	$7,928		$7,134
Amortization of deferred financing costs	822	[1]	733	[1]
Capitalized interest	-1,189		-976
Total interest expense	7,561		6,891
Accretion of debt discount	$613		$556
[1]	The three months ended March 31, 2015 and 2014 includes $613,000 and $556,000, respectively, of debt discount accretion related to the Notes.

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
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to common stockholders	($3,004)	($1,965)
Weighted average common shares outstanding basic (shares)	77,114,826	58,204,532
Weighted average common shares outstanding diluted (shares)	77,114,826	58,204,532
Basic (dollars per share)	($0.04)	($0.03)
Diluted (dollars per share)	($0.04)	($0.03)
Common shares excluded from denominator as anti-dilutive (shares)	823,881	119,496
Unvested restricted shares
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Shares	0	0
Common shares excluded from denominator as anti-dilutive (shares)	450,556	119,496
Stock options
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Shares	0	0
Common shares excluded from denominator as anti-dilutive (shares)	0	0
Unvested PBUs
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Shares	0	0
Common shares excluded from denominator as anti-dilutive (shares)	373,325	0

Commitments_And_Contingencies_

Commitments And Contingencies (Narrative) (Details) (Gastar Exploration Ltd vs US Speciality Ins Co and Axis Ins Co, USD $)	0 Months Ended
In Millions, unless otherwise specified	Dec. 17, 2010
Gastar Exploration Ltd vs US Speciality Ins Co and Axis Ins Co
Loss Contingencies [Line Items]
Settlement aggregate amount	$21.20
Combined coverage limits under directors and officers insurance	$20

Statement_Of_Cash_Flows_Supple2

Statement Of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of capitalized amounts	($282)	($697)
Non-cash transactions:
Capital expenditures excluded from accounts payable and accrued drilling costs	-10,366	-299
Capital expenditures included in accounts receivable	0	4,077
Asset retirement obligation included in oil and natural gas properties	77	28
Application of advances to operators	8,457	9,490
Other	$23	$78