Gastar Exploration (GST) 10-Q 7 Aug 14 2014 Q2 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	6 Months Ended
	Jun. 30, 2014	Aug. 04, 2014
Document And Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Jun-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'
Entity Registrant Name	'Gastar Exploration Inc.	'
Entity Central Index Key	'0001431372	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	61,791,573

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$24,763	$32,393
Accounts receivable, net of allowance for doubtful accounts of $0 and $507, respectively	20,406	21,656
Commodity derivative contracts	223	0
Prepaid expenses	982	1,145
Total current assets	46,374	55,194
Oil and natural gas properties, full cost method of accounting:	'	'
Unproved properties, excluded from amortization	104,545	96,220
Proved properties	1,000,211	935,773
Total oil and natural gas properties	1,104,756	1,031,993
Furniture and equipment	2,849	2,691
Total property, plant and equipment	1,107,605	1,034,684
Accumulated depreciation, depletion and amortization	-539,833	-517,171
Total property, plant and equipment, net	567,772	517,513
OTHER ASSETS:	'	'
Commodity derivative contracts	2,009	7,545
Deferred charges, net	2,901	2,950
Advances to operators and other assets	7,464	6,733
Total other assets	12,374	17,228
TOTAL ASSETS	626,520	589,935
CURRENT LIABILITIES:	'	'
Accounts payable	11,921	11,046
Revenue payable	27,386	12,514
Accrued interest	3,528	3,504
Accrued drilling and operating costs	5,591	8,756
Advances from non-operators	9,785	9,259
Commodity derivative contracts	6,626	3,403
Current commodity derivative premium put payable	1,377	145
Asset retirement obligation	42	633
Other accrued liabilities	3,169	4,844
Total current liabilities	69,425	54,104
LONG-TERM LIABILITIES:	'	'
Long-term debt	334,120	312,994
Commodity derivative contracts	234	378
Commodity derivative premium payable	5,952	7,000
Asset retirement obligation	5,767	5,430
Total long-term liabilities	346,073	325,802
Commitments and contingencies (Note 12)	'	'
STOCKHOLDERS' EQUITY:	'	'
Common stock	61	61
Additional paid-in capital	465,671	464,730
Accumulated deficit	-254,772	-254,823
Total stockholders' equity	211,022	210,029
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	626,520	589,935
Series A Preferred Stock	'	'
STOCKHOLDERS' EQUITY:	'	'
Preferred stock	41	40
Series B Preferred Stock	'	'
STOCKHOLDERS' EQUITY:	'	'
Preferred stock	$21	$21

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified			Series A Preferred Stock	Series A Preferred Stock	Series B Preferred Stock	Series B Preferred Stock
Accounts receivable, net of allowance for doubtful accounts	$0	$507	'	'	'	'
Preferred stock, shares authorized	40,000,000,000	40,000,000,000	10,000,000	10,000,000	10,000,000	10,000,000
Preferred stock, par value	'	'	$0.01	$0.01	$0.01	$0.01
Preferred stock, shares issued	'	'	4,045,000	3,958,160	2,140,000	2,140,000
Preferred stock, shares outstanding	'	'	4,045,000	3,958,160	2,140,000	2,140,000
Liquidation Preference	'	'	$25	$25	$25	$25
Common stock, par value	$0.00	$0.00	'	'	'	'
Common stock, shares authorized	275,000,000	275,000,000	'	'	'	'
Common stock, shares issued	61,796,023	61,211,658	'	'	'	'
Common stock, shares outstanding	61,796,023	61,211,658	'	'	'	'

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	3 Months Ended		6 Months Ended
In Thousands, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
REVENUES:	'	'	'	'
Oil and condensate	$22,342	$8,065	$39,120	$13,350
Natural gas	17,559	12,413	32,978	20,014
NGLs	4,906	3,412	11,550	5,792
Total oil, condensate, natural gas and NGLs revenues	44,807	23,890	83,648	39,156
(Loss) gain on commodity derivatives contracts	-8,910	7,036	-15,424	3,034
Total revenues	35,897	30,926	68,224	42,190
EXPENSES:	'	'	'	'
Production taxes	2,037	1,150	3,931	1,793
Lease operating expenses	4,877	2,169	8,921	4,006
Transportation, treating and gathering	2,146	1,124	2,771	2,288
Depreciation, depletion and amortization	10,280	7,596	22,662	12,961
Accretion of asset retirement obligation	125	114	247	216
General and administrative expense	3,893	4,964	8,656	7,966
Litigation settlement expense	0	0	0	1,000
Total expenses	23,358	17,117	47,188	30,230
INCOME FROM OPERATIONS	12,539	13,809	21,036	11,960
OTHER INCOME (EXPENSE):	'	'	'	'
Gain on acquisition of assets at fair value	0	43,712	0	43,712
Interest expense	-6,912	-3,545	-13,803	-4,154
Investment income and other	4	5	11	8
Foreign transaction loss	-4	-11	-6	-12
INCOME BEFORE PROVISION FOR INCOME TAXES	5,627	53,970	7,238	51,514
Provision for income taxes	0	0	0	0
NET INCOME	5,627	53,970	7,238	51,514
Dividends on preferred stock	-3,611	-2,134	-7,187	-4,264
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$2,016	$51,836	$51	$47,250
NET INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:	'	'	'	'
Basic (in dollars per share)	$0.03	$0.83	$0	$0.75
Diluted (in dollars per share)	$0.03	$0.81	$0	$0.74
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:	'	'	'	'
Basic (shares)	58,702,982	62,398,472	58,462,124	63,089,987
Diluted (shares)	61,922,874	63,813,423	61,674,267	63,699,525

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'		'
Net income	$7,238		$51,514
Adjustments to reconcile net income to net cash provided by operating activities:	'		'
Depreciation, depletion and amortization	22,662		12,961
Stock-based compensation	2,532		1,966
Total loss (gain) on commodity derivatives contracts	15,424		-3,034
Cash settlements of matured commodity derivatives contracts, net	-6,061		5,596
Cash premiums paid for commodity derivatives contracts	-155		-27
Amortization of deferred financing costs	1,491	[1]	1,450	[1]
Accretion of asset retirement obligation	247		216
Settlement of asset retirement obligation	-546		0
Gain on acquisition of assets at fair value	0		-43,712
Changes in operating assets and liabilities:	'		'
Accounts receivable	-2,827		29
Prepaid expenses	112		259
Accounts payable and accrued liabilities	9,649		9,814
Net cash provided by operating activities	49,766		37,032
CASH FLOWS FROM INVESTING ACTIVITIES:	'		'
Development and purchase of oil and natural gas properties	-55,295		-55,955
Advances to operators	-20,657		-5,154
Acquisition of oil and natural gas properties - refund (expenditure)	4,209		-69,775
Sale of natural gas and oil properties	3,077		2,300
Proceeds from non-operators	526		12,874
Purchase of furniture and equipment	-158		-151
Net cash used in investing activities	-68,298		-115,861
CASH FLOWS FROM FINANCING ACTIVITIES:	'		'
Proceeds from revolving credit facility	35,000		19,000
Repayment of revolving credit facility	-15,000		-117,000
Proceeds from issuance of senior secured notes, net of discount	0		194,500
Repurchase of outstanding common shares	0		-9,753
Proceeds from issuance of preferred stock, net of issuance costs	2,064		133
Dividends on preferred stock	-7,187		-3,554
Deferred financing charges	-319		-2,355
Tax withholding related to restricted stock and PBU vestings	-3,656		-244
Net cash provided by financing activities	10,902		80,727
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	-7,630		1,898
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	32,393		8,901
CASH AND CASH EQUIVALENTS, END OF PERIOD	$24,763		$10,799
[1]	The three and six months ended JuneB 30, 2014 includes $570,000 and $1.1 million, respectively, of debt discount accretion related to the Notes.

Description_Of_Business

Description Of Business	6 Months Ended
	Jun. 30, 2014
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 Exploration Inc.’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. Gastar Exploration Inc. is currently pursuing development within the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play in Oklahoma and the development of liquids-rich natural gas in the Marcellus Shale play and dry gas in the Utica Shale play in West Virginia.
	On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation (“Parent”), 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 USA and Gastar USA changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc., together with its subsidiaries, owns and will continue to conduct business in substantially the same manner as was being conducted by Gastar Exploration, Inc. and its subsidiaries prior to the merger.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2014
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, 2013 (the “2013 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2013 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.
	All prior year balances presented are those of Gastar Exploration, Inc.
	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 2013 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 2013 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 intercompany 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 and six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014. 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:
	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 Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company does not expect the adoption of this guidance to impact the Company's operating results, financial position or cash flows.
	Income Taxes. In July 2013, the FASB issued an amendment to previously issued guidance regarding the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The amendment requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward, except as follows. To the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The assessment of whether a deferred tax asset is available is based on the unrecognized tax benefit and deferred tax asset that exist at the reporting date and should be made presuming disallowance of the tax position at the reporting date. This amendment does not require new recurring disclosures. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this guidance did not impact the Company's operating results, financial position or cash flows.

Property_Plant_And_Equipment

Property, Plant And Equipment	6 Months Ended
	Jun. 30, 2014
Property, Plant and Equipment [Abstract]	'
Property, Plant And Equipment	'
	Property, Plant and Equipment
	The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of West Virginia, Pennsylvania, Oklahoma and Texas. The Company sold substantially all of its East Texas assets on October 2, 2013, with an effective date of January 1, 2013.
	The following table summarizes the components of unproved properties excluded from amortization for the periods indicated:
		June 30, 2014			December 31, 2013
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	10,124		$	4,774
	Acreage acquisition costs	88,086			86,097
	Capitalized interest	6,335			5,349
	Total unproved properties excluded from amortization	$	104,545		$	96,220
	For the three and six months ended June 30, 2014, 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 $234,000 and $428,000 of unproved properties to proved properties for the three and six months ended June 30, 2014, respectively, related to acreage in Marcellus East. For the three and six months ended June 30, 2013, management's evaluation of unproved properties resulted in an impairment of $7.0 million and $7.9 million, respectively, 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 our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation dictates that the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices and costs in effect are held constant indefinitely. The 12-month unweighted arithmetic average of the first-day-of-the-month prices are adjusted for basis and quality differentials in determining the present value of the reserves. The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:
		2014
		Total Impairment			30-Jun			31-Mar
	Henry Hub natural gas price (per MMBtu)(1)				$	4.1		$	3.99
	West Texas Intermediate oil price (per Bbl)(1)				$	100.11		$	98.3
	Impairment recorded (pre-tax) (in thousands)	$	—		$	—		$	—
		2013
		Total Impairment			30-Jun			31-Mar
	Henry Hub natural gas price (per MMBtu)(1)				$	3.44		$	2.95
	West Texas Intermediate oil price (per Bbl)(1)				$	91.6		$	92.63
	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.
	Chesapeake Acquisition
	On June 7, 2013, Gastar USA acquired from Chesapeake Exploration, L.L.C. and Larchmont Resources, L.L.C. (together, the “Chesapeake Parties”) approximately 157,000 net acres of Oklahoma oil and gas leasehold interests, including production from interests in 206 producing wells located in Oklahoma (the “Chesapeake Assets”) for a final adjusted purchase price of $69.4 million, reflecting adjustment for an acquisition effective date of October 1, 2012 (the “Chesapeake Acquisition”). The Company accounted for the Chesapeake Acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $2.1 million of transaction and integration costs associated with the acquisition and expensed these costs as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used were unobservable and as such, represented Level 3 inputs under the fair value hierarchy as described in Note 5, “Fair Value Measurements.” The Company's assessment of the fair value of the Chesapeake Assets resulted in a fair market valuation of $113.1 million. Upon completion of the preliminary asset valuation, the Company recorded a bargain purchase gain of $43.7 million during the second quarter of 2013. With the completion of the asset valuation during the fourth quarter of 2013, the Company recorded deferred tax attributes associated with the transaction of $16.0 million. As a result of incorporating the final valuation information into the purchase price allocation, a net bargain purchase gain of $27.7 million was recognized in 2013.
	Hunton Joint Venture and AMI Election
	Effective July 1, 2013, Gastar USA's working interest partner in its original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties that Gastar USA acquired pursuant to the Chesapeake Purchase Agreement for a total payment of $11.8 million, of which $133,000 was deemed to be a reimbursement of transaction and integration costs associated with the acquisition and was recorded as a reduction of general and administrative expense.
	Hunton Divestiture
	On August 6, 2013, Gastar USA sold approximately 76,000 net acres of oil and gas leasehold interests in Kingfisher and Canadian Counties, Oklahoma to Newfield Exploration Mid-Continent Inc. (“Newfield”) and Gastar USA acquired approximately 1,850 net acres of Oklahoma oil and gas leasehold interests from Newfield for a net cash purchase price of approximately $57.0 million, adjusted for an effective date of May 1, 2013. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.
	WEHLU Acquisition
	On November 15, 2013, Gastar USA acquired a 98.3% working interest (80.5% net revenue interest) in 24,000 net acres of the West Edmond Hunton Lime Unit (“WEHLU”) located in Kingfisher, Logan and Oklahoma Counties, Oklahoma from Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (the “Lime Rock Parties”) for an adjusted cash purchase price of $177.8 million, reflecting customary adjustments and adjustment for an acquisition effective date of August 1, 2013 (the “WEHLU Acquisition”). The Company accounted for the WEHLU Acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $286,000 of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used were unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 5, “Fair Value Measurements.” The Company's assessment of the fair value of the WEHLU assets resulted in a fair market valuation of $176.8 million. As the fair market valuation varied less than 1% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation.
	Chesapeake and WEHLU Acquisitions Pro Forma Operating Results
	The following unaudited pro forma results for the three and six months ended June 30, 2013 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of the respective periods presented. Pro forma results are not presented for the three and six months ended June 30, 2014, as the results of operations for the acquisitions are included in the Company's results of operations for those periods. The pro forma results for the three and six months ended June 30, 2013 are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.
			For the Three Months Ended June 30, 2013			For the Six Months Ended June 30, 2013
			(in thousands, except per share data)
			(Unaudited)
	Revenues		$	44,128		$	68,751
	Net Income		$	7,839		$	140
	Income per share:
	Basic		$	0.14		$	—
	Diluted		$	0.13		$	—
	The pro forma information above includes numerous assumptions, is presented for illustrative purposes only, and may not be indicative of the future results or results of operations that would have actually occurred had the Chesapeake and WEHLU Acquisitions occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information.
	Hilltop Area, East Texas Sale
	On October 2, 2013, Gastar Exploration Texas, LP (“Gastar Texas”) and Gastar USA sold to Cubic Energy, Inc. (“Cubic Energy”) approximately 31,800 gross (16,300 net) acres of leasehold interests in the Hilltop area of East Texas in Leon and Robertson Counties, Texas, including production from interests in producing wells, for net proceeds of approximately $42.9 million, reflecting adjustment for an effective date of January 1, 2013 and other customary adjustments. The Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.
	Atinum Joint Venture
	In September 2010, Gastar USA entered into a joint venture (the “Atinum Joint Venture”) pursuant to which Gastar USA 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 (the “Atinum Joint Venture Assets”). 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, Gastar USA acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay Gastar USA on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million.
	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 Gastar USA agreed to reduce the minimum wells to be drilled requirements by nine wells to 51 wells from 60 wells. At June 30, 2014, 57 gross operated horizontal wells were capable of production under the Atinum Joint Venture.

LongTerm_Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2014
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	Second Amended and Restated Revolving Credit Facility
	On June 7, 2013, Gastar USA entered into the Second Amended and Restated Credit Agreement, dated as of June 7, 2013, among Gastar USA, 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”). The Revolving Credit Facility provided an initial borrowing base of $50.0 million, with borrowings bearing interest, at Gastar USA's election, 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 or (ii) the federal funds rate plus 50 basis points. 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. 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 is guaranteed by all of the Company's current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility, in each case with the exception of those subsidiaries the Company has chosen to exclude that are deemed immaterial. 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 minimus 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 each 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; 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.
	All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including among others:
	•	Failure to make payments;
	•	Non-performance of covenants and obligations continuing beyond any applicable grace period; and
	•	The occurrence of a change in control of the Company, as defined in the New Revolving Credit Facility.
	On July 31, 2013, Gastar USA, together with the parties thereto, entered into the Waiver, Agreement and Amendment No. 1 to Second Amended and Restated Credit Agreement (the “First Amendment”). The First Amendment amended the New Revolving Credit Facility to clarify the current ratio covenant calculation.
	On October 18, 2013, Gastar USA, together with the parties thereto, entered into the Agreement and Amendment No. 2 (“Amendment No. 2”) to Second Amended and Restated Credit Agreement, dated as of June 7, 2013. Amendment No. 2 amended the Revolving Credit Facility to, among other things, (i) increase the aggregate principal amount of 8 5/8% Senior Secured Notes due 2018 permitted to be issued from $200.0 million to $325.0 million, (ii) allow for the issuance by Gastar USA of Series B Preferred Stock and (iii) increase the aggregate amount of cash dividends permitted to be paid to preferred stockholders from $12.5 million to $20.0 million.
	On December 9, 2013, the borrowing base under the Revolving Credit Facility was increased by the lending participants to $100.0 million.
	On March 12, 2014, the Company, together with the parties thereto, entered into the Agreement, Waiver and Amendment No. 3 (“Amendment No. 3”) to Second Amended and Restated Credit Agreement, dated as of June 7, 2013. Amendment No. 3 amended the Revolving Credit Facility to, among other things, (i) permit the Company to exclude current and future subsidiaries that are deemed to be immaterial from becoming guarantors of the Revolving Credit Facility, provided such non-guarantor subsidiaries comply with certain restrictions, (ii) exclude the non-guarantor subsidiaries from the provisions of the negative covenants of the Revolving Credit Facility with respect to mergers and acquisitions, restricted payments and investments and (iii) exclude the non-guarantor subsidiaries from being included in the calculation of the borrowing base under the Revolving Credit Facility.
	On March 26, 2014, the borrowing base under the Revolving Credit Facility was increased by the lending participants to $120.0 million.
	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 June 30, 2014, the Revolving Credit Facility had a borrowing base of $120.0 million, with $20.0 million of borrowings outstanding and availability of $100.0 million. The next regularly scheduled redetermination is set for November 2014. 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 June 30, 2014, the Company was in compliance with all financial covenants under the Revolving Credit Facility.
	Amended and Restated Revolving Credit Facility
	For the period October 28, 2009 through June 6, 2013, Gastar USA, together with the other parties thereto, was subject to an amended and restated credit facility (the “Prior Amended Revolving Credit Facility”). The Prior Amended Revolving Credit Facility provided for various borrowing base amounts based on an initial borrowing base of $47.5 million and a final borrowing base of $160.0 million effective March 31, 2013. Borrowings bore interest, at Gastar USA’s election, at the prime rate or LIBO rate plus an applicable margin. The applicable interest rate margin varied from 1.0% to 2.0% in the case of borrowings based on the prime rate and from 2.5% to 3.5% in the case of borrowings based on LIBO rate, depending on the utilization percentage in relation to the borrowing base. An annual commitment fee of 0.5% was payable quarterly based on the unutilized balance of the borrowing base. The Prior Amended Revolving Credit Facility had a final scheduled maturity date of September 30, 2015. The Prior Amended Revolving Credit Facility was amended and restated on June 7, 2013.
	Senior Secured Notes
	On May 15, 2013, Gastar USA issued $200.0 million aggregate principal amount of its 8 5/8% Senior Secured Notes due May 15, 2018 under an indenture (the “Indenture”) by and among Gastar USA, 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”). On November 15, 2013, Gastar USA issued an additional $125.0 million aggregate principal amount of additional notes under the Indenture. The 8 5/8% Senior Secured Notes due 2018 are collectively referred to as the “Notes.” The Notes bear interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. The Notes will mature on May 15, 2018. Gastar USA received net proceeds of approximately $312.3 million, net of debt issuance costs and any original issue discounts.
	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 are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company's material subsidiaries and certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees 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 are 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.
	In May 2014, holders of the 8 5/8% Senior Secured Notes due 2018 exchanged their notes for registered notes with the same terms.
	At June 30, 2014, the Notes reflected a balance of $314.1 million, net of unamortized discounts of $10.9 million, on the condensed consolidated balance sheets.

Fair_Value_Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties or estimated market data based on area transactions, which are Level 3 inputs. For the three and six months ended June 30, 2014, 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 $234,000 and $428,000 of unproved properties to proved properties for the three and six months ended June 30, 2014, respectively, related to acreage in Marcellus East. For the three and six months ended June 30, 2013, management's evaluation of unproved properties resulted in an impairment of $7.0 million and $7.9 million, respectively, related to Marcellus East. As no other fair value measurements are required to be recognized on a non-recurring basis at June 30, 2014, no additional disclosures are provided at June 30, 2014.
	As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:
	•	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds.
	•	Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.
	•	Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge 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 2014 and 2013 periods.
	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013:
		Fair value as of June 30, 2014
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	24,763		$	—		$	—		$	24,763
	Commodity derivative contracts	—			—			2,232			2,232
	Liabilities:
	Commodity derivative contracts	—			—			(6,860		)	(6,860		)
	Total	$	24,763		$	—		$	(4,628	)	$	20,135
		Fair value as of December 31, 2013
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	32,393		$	—		$	—		$	32,393
	Commodity derivative contracts	—			—			7,545			7,545
	Liabilities:
	Commodity derivative contracts	—			—			(3,781		)	(3,781		)
	Total	$	32,393		$	—		$	3,764		$	36,157
	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2014 and 2013. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at June 30, 2014 and 2013.
		Three Months Ended June 30,						Six Months Ended June 30,
		2014			2013			2014			2013
		(in thousands)
	Balance at beginning of period	$	620		$	(3,145	)	$	3,764		$	6,465
	Total (losses) gains included in earnings	(8,910		)	7,036			(15,424		)	3,034
	Purchases	268			—			339			27
	Issuances	—			—			—			—
	Settlements (1)	3,394			444			6,693			(5,191		)
	Transfers in and (out) of Level 3	—			—			—			—
	Balance at end of period	$	(4,628	)	$	4,335		$	(4,628	)	$	4,335
	The amount of total (losses) gains for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at June 30, 2014 and 2013	$	(5,418	)	$	7,485		$	(8,573	)	$	(2,152	)
	_________________________________
	-1	Included in loss (gain) on commodity derivatives contracts on the condensed consolidated statement of operations.
	At June 30, 2014, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at June 30, 2014 was $344.0 million based on quoted market prices of the senior secured notes (Level 1).
	The Company has consistently applied the valuation techniques discussed above in all periods presented.
	The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 6, “Derivative Instruments and Hedging Activity.”

Derivative_Instruments_and_Hed

Derivative Instruments and Hedging Activity	6 Months Ended
	Jun. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments and Hedging Activity	'
	Derivative Instruments and Hedging Activity
	The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk.
	All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the condensed consolidated statements of operations in (loss) gain on commodity derivatives contracts. For the three months ended June 30, 2014 and 2013, the Company reported losses of $8.9 million and gains of $7.0 million, respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts. For the six months ended June 30, 2014 and 2013, the Company reported losses of $15.4 million and gains of $3.0 million, respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts.
	As of June 30, 2014, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base		Floor		Short		Call		Ceiling
					Daily			Notional			Fixed		(Long)		Put		(Long)		(Short)
					Volume			Volume			Price
					(in MMBtus)
	2014		Fixed price swap		9,416			1,732,500			$	4.06	$	—	$	—	$	—	$	—
	2014		Fixed price swap		2,000			368,000			$	3.72	$	—	$	—	$	—	$	—
	2014		Fixed price swap		2,000			368,000			$	3.98	$	—	$	—	$	—	$	—
	2014		Fixed price swap		2,000			368,000			$	4.07	$	—	$	—	$	—	$	—
	2014		Fixed price swap		1,700			312,800			$	4.32	$	—	$	—	$	—	$	—
	2014		Short calls		2,500			460,000			$	—	$	—	$	—	$	—	$	4.59
	2014		Costless collar		3,000			552,000			$	—	$	4	$	—	$	—	$	4.36
	2014		Costless collar		5,000			920,000			$	—	$	4	$	—	$	—	$	4.55
	2014		Costless collar		2,500			460,000			$	—	$	4	$	—	$	—	$	5
	2014		Put spread		2,000			368,000			$	—	$	4	$	3.72	$	—	$	—
	2015 (1)		Fixed price swap		10,000			900,000			$	4.46	$	—	$	—	$	—	$	—
	2015		Fixed price swap		400			146,000			$	4	$	—	$	—	$	—	$	—
	2015		Fixed price swap		2,500			912,500			$	4.06	$	—	$	—	$	—	$	—
	2015		Protective spread		2,600			949,000			$	4	$	—	$	3.25	$	—	$	—
	2015 (1)		Producer three-way collar		3,750			337,500			$	—	$	4.6	$	3.5	$	—	$	5.34
	2015 (2)		Producer three-way collar		5,000			1,375,000			$	—	$	4	$	3.25	$	—	$	5
	2015		Producer three-way collar		2,000			760,000			$	—	$	4	$	3.25	$	—	$	4.58
	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
	_______________________________
	-1	For the period January to March 2015.
	-2	For the period April to December 2015.
	As of June 30, 2014, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base		Floor		Short		Ceiling
					Daily			Notional			Fixed		(Long)		Put		(Short)
					Volume (1)			Volume			Price
					(in Bbls)
	2014		Fixed price swap		750			138,000			$	90.35	$	—	$	—	$	—
	2014		Fixed price swap		200			36,800			$	93	$	—	$	—	$	—
	2014		Fixed price swap		350			64,400			$	91.55	$	—	$	—	$	—
	2014		Fixed price swap		500			92,000			$	91.1	$	—	$	—	$	—
	2014		Fixed price swap		250			46,000			$	90.77	$	—	$	—	$	—
	2014		Costless collar		200			36,800			$	—	$	98	$	—	$	98
	2014 (2)		Put spread		200			24,400			$	—	$	93	$	73	$	—
	2015 (3)		Costless collar		400			72,400			$	—	$	85	$	—	$	96.5
	2015 (3)		Costless collar		366			66,300			$	—	$	85	$	—	$	97.8
	2015 (3)		Costless collar		150			27,150			$	—	$	85	$	—	$	96.25
	2015 (4)		Costless three-way collar		400			73,600			$	—	$	85	$	70	$	96.5
	2015 (4)		Costless three-way collar		325			59,800			$	—	$	85	$	65	$	97.8
	2015 (4)		Costless three-way collar		50			9,200			$	—	$	85	$	65	$	96.25
	2015 (3)		Put spread		700			126,700			$	—	$	90	$	70	$	—
	2015		Put spread		250			91,250			$	—	$	89	$	69	$	—
	2015 (4)		Put spread		600			110,400			$	—	$	87	$	67	$	—
	2016		Costless three-way collar		275			100,600			$	—	$	85	$	65	$	95.1
	2016		Costless three-way collar		330			120,780			$	—	$	80	$	65	$	97.35
	2016		Put spread		550			201,300			$	—	$	85	$	65	$	—
	2016		Put spread		300			109,800			$	—	$	85.5	$	65.5	$	—
	2017		Costless three-way collar		280			102,200			$	—	$	80	$	65	$	97.25
	2017		Costless three-way collar		242			88,150			$	—	$	80	$	60	$	98.7
	2017		Put spread		500			182,500			$	—	$	82	$	62	$	—
	2018 (5)		Put spread		425			103,275			$	—	$	80	$	60	$	—
	2017		Costless three-way collar		242			88,150			$	—	$	80	$	60	$	98.7
	2017		Put spread		500			182,500			$	—	$	82	$	62	$	—
	2018 (5)		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 September to December 2014.
-3	For the period January to June 2015.
-4	For the period July to December 2015.
-5	For the period January to August 2018.
As of June 30, 2014, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
Settlement Period		Derivative Instrument		Average			Total of			Base
				Daily			Notional			Fixed
				Volume			Volume			Price
				(in Bbls)
2014		Fixed price swap		250			46,000			$	46.1
2014		Fixed price swap		250			46,000			$	48.11
2015 (1)		Fixed price swap		250			68,750			$	45.61
_______________________________
-1	For the period April to December 2015.
As of June 30, 2014, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments 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 December 2013 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company began amortizing the deferred put premium liabilities in December 2013. The following table provides information regarding the deferred put premium liabilities for the periods indicated:
	June 30, 2014				31-Dec-13
	(in thousands)
Current commodity derivative premium put payable	$	1,377			$	145
Long-term commodity derivative premium payable	5,952				7,000
Total unamortized put premium liabilities	$	7,329			$	7,145
The following table provides information regarding the amortization of the deferred put premium liabilities by year as of June 30, 2014:
	Amortization
	(in thousands)
September to December 2014	$	145
January to December 2015	2,482
January to December 2016	2,408
January to December 2017	1,460
January to August 2018	834
Total unamortized put premium liabilities	$	7,329
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		June 30, 2014				December 31, 2013
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Current assets		$	223			$	—
Commodity derivative contracts	Other assets		2,009				7,545
Commodity derivative contracts	Current liabilities		(6,626		)		(3,403		)
Commodity derivative contracts	Long-term liabilities		(234		)		(378		)
Total derivatives not designated as hedging instruments			$	(4,628	)		$	3,764
	Amount of Gain (Loss) Recognized in Income on Derivatives
			Amount of Gain (Loss)
			Recognized in Income on
			Derivatives For the Three
			Months Ended June 30,
	Location of Gain (Loss) Recognized in Income on Derivatives		2014				2013
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	(Loss) gain on commodity derivatives contracts		$	(8,910	)		$	7,036
Total			$	(8,910	)		$	7,036
	Amount of Gain (Loss) Recognized in Income on Derivatives
			Amount of Gain (Loss)
			Recognized in Income on
			Derivatives For the Six
			Months Ended June 30,
	Location of Gain (Loss) Recognized in Income on Derivatives		2014				2013
			(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	(Loss) gain on commodity derivatives contracts		$	(15,424	)		$	3,034
Total			$	(15,424	)		$	3,034

Capital_Stock

Capital Stock	6 Months Ended
	Jun. 30, 2014
Stockholders' Equity Note [Abstract]	'
Capital Stock	'
	Capital Stock
	Common Stock
	On November 14, 2013, Parent changed its jurisdiction of incorporation to the State of Delaware and entered into new articles of incorporation pursuant to which 275,000,000 shares of Parent's common stock, $0.001 par value per share, were authorized for issuance. Prior to November 14, 2013, Parent’s articles of incorporation allowed Parent to issue an unlimited number of common shares without par value.
	On January 31, 2014, Parent entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Parent merged with and into Gastar USA, a direct subsidiary of Parent, as part of a reorganization to eliminate Parent's holding company corporate structure. Pursuant to the Merger Agreement, shares of Parent's common stock were converted into the right to receive an equal number of shares of common stock of Gastar USA, which together with its subsidiaries, owns and continues to conduct business in substantially the same manner as it was being conducted by Parent and its subsidiaries immediately prior to the merger.
	Prior to its conversion, as described below, Gastar USA’s articles of incorporation allowed Gastar USA to issue 1,000 shares of common stock, without par value. There were 750 shares issued and outstanding at December 31, 2013, all of which were held by Parent.
	On May 24, 2011, Gastar USA converted from a Michigan corporation to a Delaware corporation (the “Conversion”). Following the Conversion, Gastar USA’s new Delaware certificate of incorporation allows Gastar USA to issue 1,000 shares of common stock, without par value. In connection with the Conversion, the Parent’s 750 shares of common stock in the Michigan corporation were converted to 750 shares of common stock in the new Gastar USA Delaware corporation.
	On October 25, 2013, Gastar USA filed an Amended and Restated Certificate of Incorporation (the “A&R Certificate”) with the Secretary of State of the State of Delaware. Under the A&R Certificate, the capital stock authorized for issuance was increased from 1,000 shares of common stock, without par value, to 275,000,000 shares of common stock, par value $0.001 per share.
	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 periods indicated:
		For the Three Months Ended June 30, 2014	For the Six Months Ended June 30, 2014
	Other share issuances:
	Restricted common shares granted	—	533,840
	Restricted common shares vested	1,500	1,192,796
	Common shares surrendered upon vesting (1)	410	399,766
	Common shares issued upon vesting of PBUs, net of shares surrendered for taxes	—	472,189
	Common shares forfeited	21,657	21,657
	__________________
	-1	Represents common shares forfeited in connection with the payment of estimated withholding taxes on restricted common shares 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 4,390,554 shares available for issuance under the LTIP at June 30, 2014.
	Shares Reserved
	At June 30, 2014, the Company had 874,100 common shares reserved for the exercise of stock options.
	Shares Owned by Chesapeake Energy Corporation
	On March 28, 2013, the Company entered into a Settlement Agreement, dated March 28, 2013, between Chesapeake Exploration, L.L.C. and Chesapeake Energy Corporation (collectively, “Chesapeake”) and the Company, Gastar Exploration Texas, LP and Gastar Exploration Texas, LLC (the “Settlement Agreement”). Pursuant to the Settlement Agreement, the Company settled and resolved all claims of Chesapeake and its subsidiaries against the Company and its subsidiaries made in a previously disclosed lawsuit filed in the U.S. District Court for the Southern District of Texas. In order to effect a mutual full and unconditional release and settlement of all claims made in the lawsuit filed by Chesapeake, the Company paid Chesapeake approximately $10.8 million in cash, approximately $9.8 million of which was paid for the repurchase of 6,781,768 outstanding common shares of Parent held by Chesapeake Energy Corporation upon the closing of the stock repurchase and settlement on June 7, 2013.
	Preferred Stock
	Prior to the Conversion, Gastar USA’s articles of incorporation did not authorize issuance of preferred stock.
	Following the Conversion, Gastar USA’s new Delaware certificate of incorporation allows Gastar USA to issue 10,000,000 shares of preferred stock, with $0.01 par value (the “Preferred Stock”). The Preferred Stock was permitted to be issued from time to time in one or more series. Gastar USA’s Board of Directors (the “Gastar USA Board”) was authorized to fix the number of shares of any series of Preferred Stock and to determine the designation of any such series. The Gastar USA Board was also authorized to determine or alter the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued series of Preferred Stock and, within the limits and restrictions stated in any resolution or resolutions of the Gastar USA Board originally fixing the number of shares constituting any series, to increase or decrease (but not below the number of shares of any such series outstanding) the number of shares of any series subsequent to the issues shares of that series). Pursuant to the A&R Certificate, the number of shares of Preferred Stock authorized for issuance was increased to 40,000,000 shares.
	Series A Preferred Stock
	For the three and six months ended June 30, 2014, the Company sold 49,714 shares and 86,840 shares, respectively, of its 8.625% Series A Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series A Preferred Stock”) under its at the market preferred share purchase agreement (the “ATM Agreement”) for net proceeds of $1.2 million and $2.1 million, respectively. At June 30, 2014, there were 4,045,000 total shares of Series A Preferred Stock issued and outstanding.
	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 and six months ended June 30, 2014, the Company recognized dividend expense of $2.2 million and $4.3 million, respectively, for the Series A Preferred Stock.
	Series B Preferred Stock
	On October 29, 2013, the Company sold 2,000,000 shares of 10.75% Series B Cumulative Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the “Series B Preferred Stock”), in an underwritten public offering. On November 1, 2013, the underwriters partially exercised their option to purchase additional shares of Series B Preferred Stock and purchased an additional 140,000 shares of Series B Preferred Stock. The issuance of the 2,140,000 shares of Series B Preferred Stock closed on November 7, 2013. Net proceeds from the sale of the Series B Preferred Stock were approximately $50.1 million after deducting underwriting commissions and offering expenses.
	The Series B Preferred Stock rank 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 and six months ended June 30, 2014, the Company recognized dividend expense of $1.4 million and $2.9 million, respectively, for the Series B Preferred Stock.

Equity_Compensation_Plans

Equity Compensation Plans	6 Months Ended
	Jun. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Equity Compensation Plans	'
	Equity Compensation Plans
	Share-Based Compensation Plan
	Pursuant to the LTIP, the Company's Compensation Committee agreed to allocate a portion of the 2013 and 2014 long-term incentive grants to executives as performance based units (“PBUs”). The PBUs represent a contractual right to receive shares of the Company's common stock, an amount of cash equal to the fair market value of a share of the Company's common stock, or a combination of shares of the Company's common stock and cash as of the date of settlement based on the number of PBUs to be settled. The settlement of PBUs may range from 0% to 200% of the targeted number of PBUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PBUs vest equally and settlement is determined annually over a three year period. Any PBUs not vested at each measurement date will expire.
	Compensation expense associated with PBUs is based on the grant date fair value of a single PBU as determined using a Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PBUs with shares of the Company's common stock at each measurement date, the PBU awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target number of PBUs and amortized over the life of the PBU award.
	The table below provides a summary of PBUs as of the date indicated:
			PBUs		Fair Value per Unit
	Unvested PBUs at December 31, 2013		1,065,734		$	1.56
	Granted		280,171		7.34
	Vested (1)		(355,247	)	1.56
	Forfeited		—		—
	Unvested PBUs at June 30, 2014		990,658		$	3.19
	_________________________________
	-1	The first tranche of the January 30, 2013 PBU grant vested on January 30, 2014 and settled at 200% based on the Company's share price appreciation compared to the peer group index.
	For the three and six months ended June 30, 2014, the Company recognized $430,000 and $801,000, respectively, of compensation expense associated with the PBUs granted on January 30, 2013 and 2014.

Interest_Expense

Interest Expense	6 Months Ended
	Jun. 30, 2014
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 June 30,						For the Six Months Ended June 30,
		2014			2013			2014			2013
		(in thousands)
	Interest expense:
	Cash and accrued	$	7,208		$	2,962		$	14,342		$	3,862
	Amortization of deferred financing costs (1)	758			1,372			1,491			1,450
	Capitalized interest	(1,054		)	(789		)	(2,030		)	(1,158		)
	Total interest expense	$	6,912		$	3,545		$	13,803		$	4,154
	__________________
	-1	The three and six months ended June 30, 2014 includes $570,000 and $1.1 million, respectively, of debt discount accretion related to the Notes.

Income_Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2014
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	For the three and six months ended June 30, 2014 and 2013, respectively, the Company did not recognize a current income tax benefit or provision due to the Company being in a net operating loss position for both periods.

Earnings_Per_Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2014
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	Earnings per Share
	In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.
		For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2014		2013		2014		2013
		(in thousands, except per share and share data)
	Net income attributable to common stockholders	$	2,016	$	51,836	$	51	$	47,250
	Weighted average common shares outstanding - basic	58,702,982		62,398,472		58,462,124		63,089,987
	Incremental shares from unvested restricted shares	2,514,542		1,151,451		2,563,673		607,974
	Incremental shares from outstanding stock options	112,232		1,564		106,499		1,564
	Incremental shares from outstanding PBUs	593,118		261,936		541,971		—
	Weighted average common shares outstanding - diluted	61,922,874		63,813,423		61,674,267		63,699,525
	Net income per share of common stock attributable to common stockholders:
	Basic	$	0.03	$	0.83	$	—	$	0.75
	Diluted	$	0.03	$	0.81	$	—	$	0.74
	Common shares excluded from denominator as anti-dilutive:
	Unvested restricted shares	—		—		—		1,308,507
	Stock options	—		770,200		—		859,156
	Unvested PBUs	—		—		—		48,382
	Total	—		770,200		—		2,216,045

Commitments_And_Contingencies

Commitments And Contingencies	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments And Contingencies	'
	Commitments and Contingencies
	Litigation
	Gastar Exploration USA, Inc., et al v. Williams Ohio Valley Midstream LLC (American Arbitration Association Matter No. 70-198-Y-00461-13). On July 16, 2013, Gastar USA and two similarly situated co-claimants initiated an arbitration proceeding against Williams Ohio Valley Midstream LLC (“Williams OVM”). The claimants alleged that Williams OVM had breached various agreements relating to the gathering, processing and marketing of natural gas, NGLs and condensate produced from properties that are owned in part by Gastar USA in the Marcellus Shale in Marshall and Wetzel Counties, West Virginia, and requested that an Arbitration Panel assess an unspecified amount of damages against Williams OVM for, among other claims, failure to timely construct certain gathering and processing facilities, maximize the net value of the condensate, and NGLs as provided in the agreements. On August 7, 2013, Williams OVM filed an answering statement and counterclaim for damages in excess of $612,000 in the arbitration matter. On December 31, 2013, the parties informed the Arbitration Panel that they had reached an agreement in principle to settle their disputes. The disputes were subsequently settled, on a confidential basis, between both parties on June 17, 2014. Although there were some changes to the contracts, there were no changes to existing contractual fees. After production taxes and lease operating expense reimbursement benefit, the net arbitration settlement amount received by Gastar USA was approximately $8.6 million.
	Gastar Exploration Ltd vs. U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No.2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage 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 are seeking discretionary review from the Texas Supreme Court, and their petition for review was filed on February 18, 2014. At the request of the Texas Supreme Court, the Company filed a response to the insurers petition on June 25, 2014. The Court can either grant or deny the petition. If the Court denies review or affirms the Fourteenth Court of Appeals’ ruling, the case will be remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of whether the Company's claims are securities claims covered by the insuring agreements.
	Eagle Natrium LLC v. Gastar Exploration USA, Inc., Cause No. GD-14-7208, In the Court of Common Pleas of Allegheny County, Pennsylvania. On April 22, 2014, Eagle Natrium LLC (“Eagle”), a wholly-owned subsidiary of Axiall Corporation, filed a complaint against Gastar in the Court of Common Pleas of Allegheny County, Pennsylvania seeking to enjoin Gastar's hydraulic fracturing and completion operations on three wells drilled from Gastar's Goudy pad in Marshall County, West Virginia, or conducting any activity that poses a substantial risk of harm to Eagle's brine operations. Gastar is the operator of approximately 13,700 acres in Marshall County, West Virginia, including a 3,300 gross acre oil and gas lease adjacent to Eagle's facilities. Eagle operates a subsurface brine operation which it acquired from the lessor of Gastar's lease. Eagle has asserted its right to relief based on certain of the lessor's rights which were assigned to Eagle by the lessor solely as they relate to the brine and related facilities. The complaint alleges that the contemplated operations of Gastar, which include hydraulic fracturing, pose a danger to the subsurface brine operations of Eagle. Gastar has drilled and completed 15 gross horizontal wells on this lease without any apparent incident or interference with Eagle's facilities. All wells drilled to date on this lease, including the wells principally involved in the complaint, were previously approved pursuant to the terms of Gastar's lease. Proved undeveloped well locations on this lease accounted for 87.7 Bcfe, or 19%, of the Gastar's total company proved reserves at December 31, 2013. A hearing on the request for preliminary injunction has been completed and the parties are in the process of submitting their post-hearing briefs. Management of Gastar believes the allegations to be without merit and intends to vigorously defend this matter.
	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	6 Months Ended
	Jun. 30, 2014
Supplemental Cash Flow Information [Abstract]	'
Statement Of Cash Flows - Supplemental Information	'
	Statement of Cash Flows – Supplemental Information
	The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated:
		For the Six Months Ended June 30,
		2014			2013
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	14,469		$	1,840
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued drilling costs	655			(1,031		)
	Capital expenditures excluded from accounts receivable	4,077			—
	Capital expenditures excluded from prepaid expenses	51			—
	Asset retirement obligation included in oil and natural gas properties	45			1,775
	Asset retirement obligation sold	—			(362		)
	Application of advances to operators	19,926			7,728
	Other	(3		)	157

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2014
Accounting Policies [Abstract]	'
Basis of Accounting, Policy	'
	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 2013 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 2013 Form 10-K.

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	6 Months Ended
	Jun. 30, 2014
Business Acquisition [Line Items]	'
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:
		June 30, 2014			December 31, 2013
		(in thousands)
	Unproved properties, excluded from amortization:
	Drilling in progress costs	$	10,124		$	4,774
	Acreage acquisition costs	88,086			86,097
	Capitalized interest	6,335			5,349
	Total unproved properties excluded from amortization	$	104,545		$	96,220
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:
		2014
		Total Impairment			30-Jun			31-Mar
	Henry Hub natural gas price (per MMBtu)(1)				$	4.1		$	3.99
	West Texas Intermediate oil price (per Bbl)(1)				$	100.11		$	98.3
	Impairment recorded (pre-tax) (in thousands)	$	—		$	—		$	—
		2013
		Total Impairment			30-Jun			31-Mar
	Henry Hub natural gas price (per MMBtu)(1)				$	3.44		$	2.95
	West Texas Intermediate oil price (per Bbl)(1)				$	91.6		$	92.63
	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.
WEHLU Purchase Agreement	'
Business Acquisition [Line Items]	'
Business Acquisition, Pro Forma Information	'
	The following unaudited pro forma results for the three and six months ended June 30, 2013 show the effect on the Company's consolidated results of operations as if the Chesapeake and WEHLU Acquisitions had occurred at the beginning of the respective periods presented. Pro forma results are not presented for the three and six months ended June 30, 2014, as the results of operations for the acquisitions are included in the Company's results of operations for those periods. The pro forma results for the three and six months ended June 30, 2013 are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from the Chesapeake and Lime Rock Parties adjusted for (1) the financing directly attributable to the acquisitions, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Chesapeake and WEHLU assets exclude all other historical expenses of the Chesapeake and Lime Rock Parties. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.
			For the Three Months Ended June 30, 2013			For the Six Months Ended June 30, 2013
			(in thousands, except per share data)
			(Unaudited)
	Revenues		$	44,128		$	68,751
	Net Income		$	7,839		$	140
	Income per share:
	Basic		$	0.14		$	—
	Diluted		$	0.13		$	—

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements, Recurring and Nonrecurring	'
	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013:
		Fair value as of June 30, 2014
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	24,763		$	—		$	—		$	24,763
	Commodity derivative contracts	—			—			2,232			2,232
	Liabilities:
	Commodity derivative contracts	—			—			(6,860		)	(6,860		)
	Total	$	24,763		$	—		$	(4,628	)	$	20,135
		Fair value as of December 31, 2013
		Level 1			Level 2			Level 3			Total
		(in thousands)
	Assets:
	Cash and cash equivalents	$	32,393		$	—		$	—		$	32,393
	Commodity derivative contracts	—			—			7,545			7,545
	Liabilities:
	Commodity derivative contracts	—			—			(3,781		)	(3,781		)
	Total	$	32,393		$	—		$	3,764		$	36,157
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation	'
	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2014 and 2013. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at June 30, 2014 and 2013.
		Three Months Ended June 30,						Six Months Ended June 30,
		2014			2013			2014			2013
		(in thousands)
	Balance at beginning of period	$	620		$	(3,145	)	$	3,764		$	6,465
	Total (losses) gains included in earnings	(8,910		)	7,036			(15,424		)	3,034
	Purchases	268			—			339			27
	Issuances	—			—			—			—
	Settlements (1)	3,394			444			6,693			(5,191		)
	Transfers in and (out) of Level 3	—			—			—			—
	Balance at end of period	$	(4,628	)	$	4,335		$	(4,628	)	$	4,335
	The amount of total (losses) gains for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at June 30, 2014 and 2013	$	(5,418	)	$	7,485		$	(8,573	)	$	(2,152	)
	_________________________________
	-1	Included in loss (gain) on commodity derivatives contracts on the condensed consolidated statement of operations.

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activity (Tables)	6 Months Ended
	Jun. 30, 2014
Derivative [Line Items]	'
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location	'
	The following table provides information regarding the deferred put premium liabilities for the periods indicated:
		June 30, 2014				31-Dec-13
		(in thousands)
	Current commodity derivative premium put payable	$	1,377			$	145
	Long-term commodity derivative premium payable	5,952				7,000
	Total unamortized put premium liabilities	$	7,329			$	7,145
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 June 30, 2014:
		Amortization
		(in thousands)
	September to December 2014	$	145
	January to December 2015	2,482
	January to December 2016	2,408
	January to December 2017	1,460
	January to August 2018	834
	Total unamortized put premium liabilities	$	7,329
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		June 30, 2014				December 31, 2013
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	Current assets		$	223			$	—
	Commodity derivative contracts	Other assets		2,009				7,545
	Commodity derivative contracts	Current liabilities		(6,626		)		(3,403		)
	Commodity derivative contracts	Long-term liabilities		(234		)		(378		)
	Total derivatives not designated as hedging instruments			$	(4,628	)		$	3,764
		Amount of Gain (Loss) Recognized in Income on Derivatives
				Amount of Gain (Loss)
				Recognized in Income on
				Derivatives For the Three
				Months Ended June 30,
		Location of Gain (Loss) Recognized in Income on Derivatives		2014				2013
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	(Loss) gain on commodity derivatives contracts		$	(8,910	)		$	7,036
	Total			$	(8,910	)		$	7,036
		Amount of Gain (Loss) Recognized in Income on Derivatives
				Amount of Gain (Loss)
				Recognized in Income on
				Derivatives For the Six
				Months Ended June 30,
		Location of Gain (Loss) Recognized in Income on Derivatives		2014				2013
				(in thousands)
	Derivatives not designated as hedging instruments
	Commodity derivative contracts	(Loss) gain on commodity derivatives contracts		$	(15,424	)		$	3,034
	Total			$	(15,424	)		$	3,034
Natural Gas	'
Derivative [Line Items]	'
Schedule of Notional Amounts of Outstanding Derivative Positions	'
	As of June 30, 2014, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base		Floor		Short		Call		Ceiling
					Daily			Notional			Fixed		(Long)		Put		(Long)		(Short)
					Volume			Volume			Price
					(in MMBtus)
	2014		Fixed price swap		9,416			1,732,500			$	4.06	$	—	$	—	$	—	$	—
	2014		Fixed price swap		2,000			368,000			$	3.72	$	—	$	—	$	—	$	—
	2014		Fixed price swap		2,000			368,000			$	3.98	$	—	$	—	$	—	$	—
	2014		Fixed price swap		2,000			368,000			$	4.07	$	—	$	—	$	—	$	—
	2014		Fixed price swap		1,700			312,800			$	4.32	$	—	$	—	$	—	$	—
	2014		Short calls		2,500			460,000			$	—	$	—	$	—	$	—	$	4.59
	2014		Costless collar		3,000			552,000			$	—	$	4	$	—	$	—	$	4.36
	2014		Costless collar		5,000			920,000			$	—	$	4	$	—	$	—	$	4.55
	2014		Costless collar		2,500			460,000			$	—	$	4	$	—	$	—	$	5
	2014		Put spread		2,000			368,000			$	—	$	4	$	3.72	$	—	$	—
	2015 (1)		Fixed price swap		10,000			900,000			$	4.46	$	—	$	—	$	—	$	—
	2015		Fixed price swap		400			146,000			$	4	$	—	$	—	$	—	$	—
	2015		Fixed price swap		2,500			912,500			$	4.06	$	—	$	—	$	—	$	—
	2015		Protective spread		2,600			949,000			$	4	$	—	$	3.25	$	—	$	—
	2015 (1)		Producer three-way collar		3,750			337,500			$	—	$	4.6	$	3.5	$	—	$	5.34
	2015 (2)		Producer three-way collar		5,000			1,375,000			$	—	$	4	$	3.25	$	—	$	5
	2015		Producer three-way collar		2,000			760,000			$	—	$	4	$	3.25	$	—	$	4.58
	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
	_______________________________
	-1	For the period January to March 2015.
	-2	For the period April to December 2015.
Crude Oil	'
Derivative [Line Items]	'
Schedule of Notional Amounts of Outstanding Derivative Positions	'
	As of June 30, 2014, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base		Floor		Short		Ceiling
					Daily			Notional			Fixed		(Long)		Put		(Short)
					Volume (1)			Volume			Price
					(in Bbls)
	2014		Fixed price swap		750			138,000			$	90.35	$	—	$	—	$	—
	2014		Fixed price swap		200			36,800			$	93	$	—	$	—	$	—
	2014		Fixed price swap		350			64,400			$	91.55	$	—	$	—	$	—
	2014		Fixed price swap		500			92,000			$	91.1	$	—	$	—	$	—
	2014		Fixed price swap		250			46,000			$	90.77	$	—	$	—	$	—
	2014		Costless collar		200			36,800			$	—	$	98	$	—	$	98
	2014 (2)		Put spread		200			24,400			$	—	$	93	$	73	$	—
	2015 (3)		Costless collar		400			72,400			$	—	$	85	$	—	$	96.5
	2015 (3)		Costless collar		366			66,300			$	—	$	85	$	—	$	97.8
	2015 (3)		Costless collar		150			27,150			$	—	$	85	$	—	$	96.25
	2015 (4)		Costless three-way collar		400			73,600			$	—	$	85	$	70	$	96.5
	2015 (4)		Costless three-way collar		325			59,800			$	—	$	85	$	65	$	97.8
	2015 (4)		Costless three-way collar		50			9,200			$	—	$	85	$	65	$	96.25
	2015 (3)		Put spread		700			126,700			$	—	$	90	$	70	$	—
	2015		Put spread		250			91,250			$	—	$	89	$	69	$	—
	2015 (4)		Put spread		600			110,400			$	—	$	87	$	67	$	—
	2016		Costless three-way collar		275			100,600			$	—	$	85	$	65	$	95.1
	2016		Costless three-way collar		330			120,780			$	—	$	80	$	65	$	97.35
	2016		Put spread		550			201,300			$	—	$	85	$	65	$	—
	2016		Put spread		300			109,800			$	—	$	85.5	$	65.5	$	—
	2017		Costless three-way collar		280			102,200			$	—	$	80	$	65	$	97.25
	2017		Costless three-way collar		242			88,150			$	—	$	80	$	60	$	98.7
	2017		Put spread		500			182,500			$	—	$	82	$	62	$	—
	2018 (5)		Put spread		425			103,275			$	—	$	80	$	60	$	—
	2017		Costless three-way collar		242			88,150			$	—	$	80	$	60	$	98.7
	2017		Put spread		500			182,500			$	—	$	82	$	62	$	—
	2018 (5)		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 September to December 2014.
	-3	For the period January to June 2015.
	-4	For the period July to December 2015.
	-5	For the period January to August 2018.
Natural Gas Liquids	'
Derivative [Line Items]	'
Schedule of Notional Amounts of Outstanding Derivative Positions	'
	As of June 30, 2014, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
	Settlement Period		Derivative Instrument		Average			Total of			Base
					Daily			Notional			Fixed
					Volume			Volume			Price
					(in Bbls)
	2014		Fixed price swap		250			46,000			$	46.1
	2014		Fixed price swap		250			46,000			$	48.11
	2015 (1)		Fixed price swap		250			68,750			$	45.61
	_______________________________
	-1	For the period April to December 2015.

Capital_Stock_Tables

Capital Stock (Tables)	6 Months Ended
	Jun. 30, 2014
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 periods indicated:
		For the Three Months Ended June 30, 2014	For the Six Months Ended June 30, 2014
	Other share issuances:
	Restricted common shares granted	—	533,840
	Restricted common shares vested	1,500	1,192,796
	Common shares surrendered upon vesting (1)	410	399,766
	Common shares issued upon vesting of PBUs, net of shares surrendered for taxes	—	472,189
	Common shares forfeited	21,657	21,657
	__________________
	-1	Represents common shares forfeited in connection with the payment of estimated withholding taxes on restricted common shares that vested during the period.

Equity_Compensation_Plans_Tabl

Equity Compensation Plans (Tables)	6 Months Ended
	Jun. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of Share-based Compensation, Stock Options, Activity	'
	The table below provides a summary of PBUs as of the date indicated:
			PBUs		Fair Value per Unit
	Unvested PBUs at December 31, 2013		1,065,734		$	1.56
	Granted		280,171		7.34
	Vested (1)		(355,247	)	1.56
	Forfeited		—		—
	Unvested PBUs at June 30, 2014		990,658		$	3.19
	_________________________________
	-1	The first tranche of the January 30, 2013 PBU grant vested on January 30, 2014 and settled at 200% based on the Company's share price appreciation compared to the peer group index.

Interest_Expense_Tables

Interest Expense (Tables)	6 Months Ended
	Jun. 30, 2014
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 June 30,						For the Six Months Ended June 30,
		2014			2013			2014			2013
		(in thousands)
	Interest expense:
	Cash and accrued	$	7,208		$	2,962		$	14,342		$	3,862
	Amortization of deferred financing costs (1)	758			1,372			1,491			1,450
	Capitalized interest	(1,054		)	(789		)	(2,030		)	(1,158		)
	Total interest expense	$	6,912		$	3,545		$	13,803		$	4,154
	__________________
	-1	The three and six months ended June 30, 2014 includes $570,000 and $1.1 million, respectively, of debt discount accretion related to the Notes.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2014
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share, Basic and Diluted	'
		For the Three Months Ended June 30,				For the Six Months Ended June 30,
		2014		2013		2014		2013
		(in thousands, except per share and share data)
	Net income attributable to common stockholders	$	2,016	$	51,836	$	51	$	47,250
	Weighted average common shares outstanding - basic	58,702,982		62,398,472		58,462,124		63,089,987
	Incremental shares from unvested restricted shares	2,514,542		1,151,451		2,563,673		607,974
	Incremental shares from outstanding stock options	112,232		1,564		106,499		1,564
	Incremental shares from outstanding PBUs	593,118		261,936		541,971		—
	Weighted average common shares outstanding - diluted	61,922,874		63,813,423		61,674,267		63,699,525
	Net income per share of common stock attributable to common stockholders:
	Basic	$	0.03	$	0.83	$	—	$	0.75
	Diluted	$	0.03	$	0.81	$	—	$	0.74
	Common shares excluded from denominator as anti-dilutive:
	Unvested restricted shares	—		—		—		1,308,507
	Stock options	—		770,200		—		859,156
	Unvested PBUs	—		—		—		48,382
	Total	—		770,200		—		2,216,045

Statement_Of_Cash_Flows_Supple1

Statement Of Cash Flows - Supplemental Information (Tables)	6 Months Ended
	Jun. 30, 2014
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 Six Months Ended June 30,
		2014			2013
		(in thousands)
	Cash paid for interest, net of capitalized amounts	$	14,469		$	1,840
	Non-cash transactions:
	Capital expenditures excluded from accounts payable and accrued drilling costs	655			(1,031		)
	Capital expenditures excluded from accounts receivable	4,077			—
	Capital expenditures excluded from prepaid expenses	51			—
	Asset retirement obligation included in oil and natural gas properties	45			1,775
	Asset retirement obligation sold	—			(362		)
	Application of advances to operators	19,926			7,728
	Other	(3		)	157

Property_Plant_And_Equipment_N

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

3 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

1 Months Ended

6 Months Ended

0 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Aug. 06, 2013

1-May-13

Jun. 07, 2013

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Jun. 07, 2013

Aug. 06, 2013

Nov. 15, 2013

Nov. 15, 2013

Jan. 01, 2013

Oct. 02, 2013

Jul. 01, 2013

Jul. 01, 2013

Sep. 30, 2010

Jun. 30, 2014

Jun. 30, 2014

Jun. 07, 2013

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Hunton Divestiture

Hunton Divestiture

Chesapeake Assets

Chesapeake Assets

Chesapeake Assets

Chesapeake Assets

Chesapeake Assets

Oklahoma Oil and Gas Leasehold Interests

WEHLU Purchase Agreement

WEHLU Purchase Agreement

East Texas

East Texas

Hunton Joint Venture

Hunton Joint Venture

Atinum Joint Venture

Atinum Joint Venture

Atinum Joint Venture

General and administrative expenses

acre

acre

acre

acre

acre

acre

well

Maximum

Chesapeake Assets

well

well

Property, Plant and Equipment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount reclassified from unproved to proved properties

$234,000

'

$428,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of unproved properties

'

7,000,000

'

7,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net acres (acres)

'

'

'

'

76,000

'

'

'

'

'

157,000

1,850

'

24,000

'

16,300

'

12,800

'

'

'

'

Productive conventional wells (wells)

'

'

'

'

'

'

'

'

'

'

206

'

'

'

'

'

'

'

'

'

'

'

Adjusted purchase price

'

'

'

'

'

'

69,400,000

'

'

'

'

'

177,800,000

'

'

'

'

'

70,000,000

'

'

'

Transaction and integration costs

'

'

'

'

'

'

'

'

'

'

'

'

286,000

'

'

'

133,000

'

'

'

'

2,100,000

Fair market valuation

'

'

'

'

'

'

'

'

'

'

113,100,000

'

'

'

'

'

'

'

'

'

'

'

Gain on acquisition of assets at fair value

0

43,712,000

0

43,712,000

'

'

'

'

43,700,000

27,700,000

'

'

'

'

'

'

'

'

'

'

'

'

Deferred tax attributes associated with completion of asset valuation

'

'

'

'

'

'

'

16,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments to acquire oil and gas property

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,800,000

'

'

'

'

'

Total consideration

'

'

'

'

'

57,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Working interest in wells (percentage)

'

'

'

'

'

'

'

'

'

'

'

'

'

98.30%

'

'

'

'

50.00%

'

'

'

Net revenue interest in wells

'

'

'

'

'

'

'

'

'

'

'

'

'

80.50%

'

'

'

'

'

'

'

'

Preliminary assessment of the fair value of assets acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

176,800,000

'

'

'

'

'

'

'

'

Gross acres (acres)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,800

'

'

'

'

'

'

Proceeds from (payment related to) sale of oil and natural gas properties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$42,900,000

'

'

'

'

'

'

'

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

'

'

Total wells to be drilled (wells)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60

'

Total reduction in minimum wells to be drilled (wells)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51

'

Total revised gross wells on production in current year (wells)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

57

'

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Unproved properties, excluded from amortization:	'	'
Drilling in progress costs	$10,124	$4,774
Acreage acquisition costs	88,086	86,097
Capitalized interest	6,335	5,349
Total unproved properties excluded from amortization	$104,545	$96,220

Property_Plant_And_Equipment_A

Property, Plant And Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) (USD $)	3 Months Ended								6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014		Mar. 31, 2014		Jun. 30, 2013		Mar. 31, 2013		Jun. 30, 2014	Jun. 30, 2013
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'		'		'		'		'	'
Impairment recorded (pre-tax) (in thousands)	$0		$0		$0		$0		$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	4.1	[1]	3.99	[1]	3.44	[1]	2.95	[1]	'	'
West Texas Intermediate oil price (per Bbl)	'		'		'		'		'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'		'		'		'		'	'
Average price per Mcfe	100.11	[1]	98.3	[1]	91.6	[1]	92.63	[1]	'	'
[1]	For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub natural gas prices and West Texas Intermediate oil prices.

Property_Plant_And_Equipment_S1

Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) (Gastar Exploration USA, WEHLU Purchase Agreement, USD $)	3 Months Ended	6 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2013	Jun. 30, 2013
Gastar Exploration USA | WEHLU Purchase Agreement	'	'
Business Acquisition [Line Items]	'	'
Revenues	$44,128	$68,751
Net Income	$7,839	$140
Basic	$0.14	$0
Diluted	$0.13	$0

LongTerm_Debt_Narrative_Detail

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

Jun. 30, 2014

Dec. 31, 2013

Mar. 26, 2014

Jun. 30, 2014

Oct. 18, 2013

Oct. 17, 2013

Jun. 30, 2014

Dec. 09, 2013

Jun. 07, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 07, 2013

Jun. 07, 2013

Jun. 07, 2013

Jun. 07, 2013

Jun. 07, 2013

Oct. 28, 2009

Mar. 31, 2013

Oct. 28, 2009

Oct. 28, 2009

Oct. 28, 2009

Oct. 28, 2009

Oct. 28, 2009

Oct. 28, 2009

Oct. 28, 2009

Nov. 15, 2013

15-May-13

Nov. 15, 2013

Oct. 18, 2013

Oct. 17, 2013

15-May-13

Second Amended and Restated Revolving Credit Facility

Senior Secured Notes Due 2018

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Senior Secured Notes

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Second Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Amended and Restated Revolving Credit Facility

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Senior Secured Notes Due 2018

Minimum

Maximum

Federal Funds Rate

Prime Rate

Prime Rate

Eurodollar Rate

Eurodollar Rate

Prime Rate

Prime Rate

Prime Rate

LIBO Rate

LIBO Rate

LIBO Rate

Senior Secured Notes

Senior Secured Notes

Senior Secured Notes

Senior Secured Notes

Senior Secured Notes

Senior Secured Notes

Each quarter thereafter

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving credit facility borrowing base

'

'

$120,000,000

'

'

'

$120,000,000

$100,000,000

$50,000,000

'

'

'

'

'

'

'

'

$160,000,000

$47,500,000

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate description

'

'

'

'

'

'

'

'

'

'

'

'federal funds rate plus

'

'

'

'

'

'

'

'prime rate

'

'

'LIBO

'

'

'

'

'

'

'

'

Applicable interest margin (percentage)

'

'

'

'

'

'

'

'

'

'

'

500.00%

1.00%

2.00%

2.00%

3.00%

'

'

'

'

1.00%

2.00%

'

2.50%

3.50%

'

'

'

'

'

'

Annual commitment fee (percentage)

'

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility covenant compliance Current Ratio

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility covenant compliance indebtedness to EBITDA Ratio

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125,000,000

325,000,000

200,000,000

200,000,000

Aggregate amount of cash dividends permitted to be paid to preferred stockholders

'

'

'

'

20,000,000

12,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Borrowings outstanding

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Borrowing availability

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in adjusted consolidated net tangibles assets

'

'

'

'

'

'

17.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.63%

'

'

8.63%

Net proceeds received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

312,300,000

'

'

'

'

'

Percentage of aggregate principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

101.00%

'

'

'

'

Long-term debt

334,120,000

312,994,000

'

314,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized discounts

'

'

'

$10,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Amount reclassified from unproved to proved properties	$234,000	'	$428,000	'
Impairment of unproved properties	'	7,000,000	'	7,900,000
Level 1	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Fair value of long-term debt	$344,000,000	'	$344,000,000	'

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) (Fair Value, Measurements, Recurring, USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Assets [Abstract]	'	'
Assets, Commodity derivative contracts	$2,232	$7,545
Liabilities:	'	'
Liabilities, Commodity derivative contracts	-6,860	-3,781
Total	20,135	36,157
Level 1	'	'
Derivative Assets [Abstract]	'	'
Assets, Commodity derivative contracts	0	0
Liabilities:	'	'
Liabilities, Commodity derivative contracts	0	0
Total	24,763	32,393
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	2,232	7,545
Liabilities:	'	'
Liabilities, Commodity derivative contracts	-6,860	-3,781
Total	-4,628	3,764
Cash and Cash Equivalents	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	24,763	32,393
Cash and Cash Equivalents | Level 1	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	24,763	32,393
Cash and Cash Equivalents | Level 2	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	0	0
Cash and Cash Equivalents | Level 3	'	'
Derivative Assets [Abstract]	'	'
Cash and cash equivalents	$0	$0

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				6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'		'		'
Balance at beginning of period	$620		($3,145)		$3,764		$6,465
Total (losses) gains included in earnings	-8,910		7,036		-15,424		3,034
Purchases	268		0		339		27
Issuances	0		0		0		0
Settlements	3,394	[1]	444	[1]	6,693	[1]	-5,191	[1]
Transfers in and (out) of Level 3	0		0		0		0
Balance at end of period	-4,628		4,335		-4,628		4,335
(Loss) gain on commodity derivatives contracts	'		'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'		'		'
The amount of total (losses) gains for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at June 30, 2014 and 2013	($5,418)		$7,485		($8,573)		($2,152)
[1]	Included in loss (gain) on commodity derivatives contracts on the condensed consolidated statement of operations.

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activity (Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'	'	'
(Loss) gain on commodity derivatives contracts	($8,910)	$7,036	($15,424)	$3,034

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	6 Months Ended
	Jun. 30, 2014
	MMBTU
Natural Gas | 2014 | Short calls	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	460,000
Ceiling (Short) (Price per MMBtu)	4.59
Natural Gas | 2015 | Protective Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,600
Total of Notional Volume (MMBtu's or Bbls)	949,000
Base Fixed Price (Price per MMbtu or Bbl)	4
Short Put (Price per MMBtu)	3.25
Natural Gas | 2016 | Protective Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	732,000
Base Fixed Price (Price per MMbtu or Bbl)	4.11
Short Put (Price per MMBtu)	3.25
Natural Gas | 2016 | Producer Three Way Collar	'
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
Crude Oil | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	200	[1]
Total of Notional Volume (MMBtu's or Bbls)	36,800
Floor (Long) (Price per MMBtu)	98
Ceiling (Short) (Price per MMBtu)	98
Crude Oil | 2015 | Costless Three Way Collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	400	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	73,600	[2]
Floor (Long) (Price per MMBtu)	85	[2]
Short Put (Price per MMBtu)	70	[2]
Ceiling (Short) (Price per MMBtu)	96.5	[2]
Crude Oil | 2016 | Costless Three Way Collar	'
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
Crude Oil | 2017 | Costless Three Way Collar	'
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
Natural Gas Liquids | 2015 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	250	[3]
Total of Notional Volume (MMBtu's or Bbls)	68,750	[3]
Base Fixed Price (Price per MMbtu or Bbl)	45.61	[3]
Fixed Price Swap 1 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	9,416
Total of Notional Volume (MMBtu's or Bbls)	1,732,500
Base Fixed Price (Price per MMbtu or Bbl)	4.06
Fixed Price Swap 1 | Natural Gas | 2015 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	10,000	[4]
Total of Notional Volume (MMBtu's or Bbls)	900,000	[4]
Base Fixed Price (Price per MMbtu or Bbl)	4.46	[4]
Fixed Price Swap 1 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	750	[1]
Total of Notional Volume (MMBtu's or Bbls)	138,000
Base Fixed Price (Price per MMbtu or Bbl)	90.35
Fixed Price Swap 1 | Natural Gas Liquids | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	250
Total of Notional Volume (MMBtu's or Bbls)	46,000
Base Fixed Price (Price per MMbtu or Bbl)	46.1
Fixed Price Swap 2 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	368,000
Base Fixed Price (Price per MMbtu or Bbl)	3.72
Fixed Price Swap 2 | Natural Gas | 2015 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	400
Total of Notional Volume (MMBtu's or Bbls)	146,000
Base Fixed Price (Price per MMbtu or Bbl)	4
Fixed Price Swap 2 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	200	[1]
Total of Notional Volume (MMBtu's or Bbls)	36,800
Base Fixed Price (Price per MMbtu or Bbl)	93
Fixed Price Swap 2 | Natural Gas Liquids | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	250
Total of Notional Volume (MMBtu's or Bbls)	46,000
Base Fixed Price (Price per MMbtu or Bbl)	48.11
Fixed Price Swap 3 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	368,000
Base Fixed Price (Price per MMbtu or Bbl)	3.98
Fixed Price Swap 3 | Natural Gas | 2015 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	912,500
Base Fixed Price (Price per MMbtu or Bbl)	4.06
Fixed Price Swap 3 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	350	[1]
Total of Notional Volume (MMBtu's or Bbls)	64,400
Base Fixed Price (Price per MMbtu or Bbl)	91.55
Fixed Price Swap 4 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	368,000
Base Fixed Price (Price per MMbtu or Bbl)	4.07
Fixed Price Swap 4 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	500	[1]
Total of Notional Volume (MMBtu's or Bbls)	92,000
Base Fixed Price (Price per MMbtu or Bbl)	91.1
Fixed Price Swap 5 | Natural Gas | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	1,700
Total of Notional Volume (MMBtu's or Bbls)	312,800
Base Fixed Price (Price per MMbtu or Bbl)	4.32
Fixed Price Swap 5 | Crude Oil | 2014 | Fixed price swap	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	250	[1]
Total of Notional Volume (MMBtu's or Bbls)	46,000
Base Fixed Price (Price per MMbtu or Bbl)	90.77
Costless Collar 1 | Natural Gas | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	3,000
Total of Notional Volume (MMBtu's or Bbls)	552,000
Floor (Long) (Price per MMBtu)	4
Ceiling (Short) (Price per MMBtu)	4.36
Costless Collar 1 | Crude Oil | 2015 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	400	[1],[5]
Total of Notional Volume (MMBtu's or Bbls)	72,400	[5]
Floor (Long) (Price per MMBtu)	85	[5]
Ceiling (Short) (Price per MMBtu)	96.5	[5]
Costless Collar 2 | Natural Gas | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtu's or Bbls)	920,000
Floor (Long) (Price per MMBtu)	4
Ceiling (Short) (Price per MMBtu)	4.55
Costless Collar 2 | Crude Oil | 2015 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	366	[1],[5]
Total of Notional Volume (MMBtu's or Bbls)	66,300	[5]
Floor (Long) (Price per MMBtu)	85	[5]
Ceiling (Short) (Price per MMBtu)	97.8	[5]
Costless Collar 3 | Natural Gas | 2014 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtu's or Bbls)	460,000
Floor (Long) (Price per MMBtu)	4
Ceiling (Short) (Price per MMBtu)	5
Costless Collar 3 | Crude Oil | 2015 | Costless collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	150	[1],[5]
Total of Notional Volume (MMBtu's or Bbls)	27,150	[5]
Floor (Long) (Price per MMBtu)	85	[5]
Short Put (Price per MMBtu)	0	[2]
Ceiling (Short) (Price per MMBtu)	96.25	[5]
Put Spread 1 | Natural Gas | 2014 | Put Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	368,000
Floor (Long) (Price per MMBtu)	4
Short Put (Price per MMBtu)	3.72
Ceiling (Short) (Price per MMBtu)	0
Put Spread 1 | Crude Oil | 2014 | Put Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	200	[1],[6]
Total of Notional Volume (MMBtu's or Bbls)	24,400	[6]
Floor (Long) (Price per MMBtu)	93	[6]
Short Put (Price per MMBtu)	73	[6]
Put Spread 1 | Crude Oil | 2015 | Put Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	700	[1],[5]
Total of Notional Volume (MMBtu's or Bbls)	126,700	[5]
Floor (Long) (Price per MMBtu)	90	[5]
Short Put (Price per MMBtu)	70	[5]
Put Spread 1 | Crude Oil | 2016 | Put Spread	'
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 1 | Crude Oil | 2017 | Put Spread	'
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 1 | Crude Oil | 2018 | Put Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	425	[1],[7]
Total of Notional Volume (MMBtu's or Bbls)	103,275	[7]
Floor (Long) (Price per MMBtu)	80	[7]
Short Put (Price per MMBtu)	60	[7]
Put Spread 2 | Crude Oil | 2015 | Put Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	250	[1]
Total of Notional Volume (MMBtu's or Bbls)	91,250
Floor (Long) (Price per MMBtu)	89
Short Put (Price per MMBtu)	69
Put Spread 2 | Crude Oil | 2016 | Put Spread	'
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 2 | Crude Oil | Two Thousand And Sixteen [Member] | Put Spread	'
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 3 | Crude Oil | 2015 | Put Spread	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	600	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	110,400	[2]
Floor (Long) (Price per MMBtu)	87	[2]
Short Put (Price per MMBtu)	67	[2]
Producer Three Way Collar 1 | Natural Gas | 2015 | Producer Three Way Collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	3,750	[4]
Total of Notional Volume (MMBtu's or Bbls)	337,500	[4]
Floor (Long) (Price per MMBtu)	4.6	[4]
Short Put (Price per MMBtu)	3.5	[4]
Ceiling (Short) (Price per MMBtu)	5.34	[4]
Producer Three Way Collar 2 | Natural Gas | 2015 | Producer Three Way Collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	5,000	[3]
Total of Notional Volume (MMBtu's or Bbls)	1,375,000	[3]
Floor (Long) (Price per MMBtu)	4	[3]
Short Put (Price per MMBtu)	3.25	[3]
Ceiling (Short) (Price per MMBtu)	5	[3]
Producer Three Way Collar 3 | Natural Gas | 2015 | Producer Three Way Collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtu's or Bbls)	760,000
Floor (Long) (Price per MMBtu)	4
Short Put (Price per MMBtu)	3.25
Ceiling (Short) (Price per MMBtu)	4.58
Costless Three Way Collar 2 | Crude Oil | 2015 | Costless Three Way Collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	325	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	59,800	[2]
Floor (Long) (Price per MMBtu)	85	[2]
Short Put (Price per MMBtu)	65	[2]
Ceiling (Short) (Price per MMBtu)	97.8	[2]
Costless Three Way Collar 2 | Crude Oil | 2016 | Costless Three Way Collar	'
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 2 | Crude Oil | 2017 | Costless Three Way Collar	'
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
Cost Less Three Way Collar 3 | Crude Oil | 2015 | Costless Three Way Collar	'
Derivative [Line Items]	'
Average Daily Volume (MMBtus or Bbls)	50	[1],[2]
Total of Notional Volume (MMBtu's or Bbls)	9,200	[2]
Floor (Long) (Price per MMBtu)	85	[2]
Short Put (Price per MMBtu)	65	[2]
Ceiling (Short) (Price per MMBtu)	96.25	[2]
Cost Less Three Way Collar 3 | Crude Oil | 2017 | Costless Three Way Collar	'
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
[1]	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
[2]	For the period July to December 2015.
[3]	For the period April to December 2015.
[4]	For the period January to March 2015.
[5]	For the period January to June 2015.
[6]	For the period September to December 2014.
[7]	For the period January to August 2018.

Derivative_Instruments_and_Hed4

Derivative Instruments and Hedging Activity Schedule of Unamortized Put Premium Liabilities (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Current commodity derivative premium put payable	$1,377	$145
Long-term commodity derivative premium payable	5,952	7,000
Total unamortized put premium liabilities	$7,329	$7,145

Derivative_Instruments_and_Hed5

Derivative Instruments and Hedging Activity (Schedule of Future Amortization of Put Premium) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
September to December 2014	$145	'
January to December 2015	2,482	'
January to December 2016	2,408	'
January to December 2017	1,460	'
January to August 2018	834	'
Total unamortized put premium liabilities	$7,329	$7,145

Derivative_Instruments_and_Hed6

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		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Derivatives, Fair Value [Line Items]	'	'	'	'	'
Total derivatives not designated as hedging instruments	($4,628)	'	($4,628)	'	$3,764
Amount of Gain (Loss) Recognized in Income on Derivatives	-8,910	7,036	-15,424	3,034	'
(Loss) gain on commodity derivatives contracts	'	'	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'	'	'
Amount of Gain (Loss) Recognized in Income on Derivatives	-8,910	7,036	-15,424	3,034	'
Current assets	'	'	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'	'	'
Commodity derivative contracts, Assets	223	'	223	'	0
Other assets	'	'	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'	'	'
Commodity derivative contracts, Assets	2,009	'	2,009	'	7,545
Current liabilities	'	'	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'	'	'
Commodity derivative contracts, Liabilities	-6,626	'	-6,626	'	-3,403
Long-term liabilities	'	'	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'	'	'
Commodity derivative contracts, Liabilities	($234)	'	($234)	'	($378)

Capital_Stock_Narrative_Detail

Capital Stock (Narrative) (Details) (USD $)

3 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

0 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Nov. 14, 2013

Jun. 07, 2013

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Nov. 07, 2013

Oct. 29, 2013

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Nov. 07, 2013

Nov. 01, 2013

Oct. 29, 2013

Dec. 31, 2013

Oct. 25, 2013

Oct. 24, 2013

24-May-11

Jun. 30, 2014

Jun. 30, 2014

Apr. 24, 2014

Jun. 30, 2014

Chesapeake Energy Corporation

Series A Preferred Stock

Series A Preferred Stock

Series A Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Series B Preferred Stock

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Gastar Exploration USA

Parent's 2006 Long-Term Stock Incentive Plan

Parent's 2006 Long-Term Stock Incentive Plan

Series A Preferred Stock

Series A Preferred Stock

At The Market Sales Agreement

At The Market Sales Agreement

Class of Stock [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common shares authorized for issuance (shares)

275,000,000

'

275,000,000

'

275,000,000

275,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

275,000,000

1,000

1,000

'

'

'

'

Common stock, par value

$0.00

'

$0.00

'

$0.00

$0.00

'

'

'

'

'

'

'

'

'

'

'

'

'

$0.00

'

'

'

'

'

'

Common shares issued (shares)

61,796,023

'

61,796,023

'

61,211,658

'

'

'

'

'

'

'

'

'

'

'

'

'

750

'

'

750

'

'

'

'

Common stock, shares outstanding

61,796,023

'

61,796,023

'

61,211,658

'

'

'

'

'

'

'

'

'

'

'

'

'

750

'

'

'

'

'

'

'

Increase in the number of share reserved for issuance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

Common shares reserved for the exercise of stock options (shares)

874,100

'

874,100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,390,554

Payment to settle legal claim

'

'

'

'

'

'

$10,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments for repurchase of outstanding common shares

'

'

0

9,753,000

'

'

9,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repurchase of outstanding common shares (shares)

'

'

'

'

'

'

6,781,768

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred shares authorized for issuance (shares)

40,000,000,000

'

40,000,000,000

'

40,000,000,000

'

'

10,000,000

10,000,000

10,000,000

'

'

10,000,000

10,000,000

10,000,000

'

'

'

'

40,000,000

'

10,000,000

'

'

'

'

Preferred stock par value per share

'

'

'

'

'

'

'

$0.01

$0.01

$0.01

'

'

$0.01

$0.01

$0.01

'

'

$0.01

'

'

'

$0.01

'

'

'

'

Shares issued of Series A Preferred Stock

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

49,714

86,840

'

'

Proceeds from issuance of preferred stock, net of issuance costs

'

'

2,064,000

133,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000

2,100,000

'

'

Preferred stock, shares sold (shares)

'

'

'

'

'

'

'

4,045,000

4,045,000

3,958,160

'

'

2,140,000

2,140,000

2,140,000

2,140,000

'

2,000,000

'

'

'

'

4,045,000

4,045,000

'

'

Liquidation Preference

'

'

'

'

'

'

'

$25

$25

$25

'

'

$25

$25

$25

'

'

$25

'

'

'

'

'

'

'

'

Preferred stock, dividend rate, percentage (percentage)

'

'

'

'

'

'

'

'

8.63%

'

'

10.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends on preferred stock

-3,611,000

-2,134,000

-7,187,000

-4,264,000

'

'

'

-2,200,000

-4,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of additional shares under option to purchase shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

140,000

'

'

'

'

'

'

'

'

'

Net proceeds expected from offering of Series B Preferred Stock

'

'

'

'

'

'

'

'

'

'

50,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock redemption price per share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$25

'

'

'

'

'

'

'

'

'

'

Option to convert shares of Series B Preferred Stock

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.5207

'

'

'

'

'

'

'

'

'

'

Recognized dividend expense

'

'

'

'

'

'

'

'

'

'

'

'

$1,400,000

$2,900,000

'

'

'

'

'

'

'

'

'

'

'

'

Capital_Stock_Schedule_of_Issu

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details) (Unvested restricted shares)	3 Months Ended		6 Months Ended
	Jun. 30, 2014		Jun. 30, 2014
Unvested restricted shares	'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'
Restricted common shares granted (shares)	0		533,840
Restricted common shares vested (shares)	1,500		1,192,796
Common shares forfeited (shares)	410	[1]	399,766	[1]
Common shares issued upon vesting of PBUs, net of shares surrendered for taxes	0		472,189
Common shares forfeited (shares)	21,657		21,657
[1]	Represents common shares forfeited in connection with the payment of estimated withholding taxes on restricted common shares that vested during the period.

Equity_Compensation_Plans_Narr

Equity Compensation Plans (Narrative) (Details) (Unvested PBUs, USD $)	3 Months Ended	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Compensation expense	$430	$801
2006 Long-Term Stock Incentive Plan	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Settlement of PBU's (percentage)	100.00%	100.00%
2006 Long-Term Stock Incentive Plan | Minimum	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Settlement of PBU's (percentage)	0.00%	0.00%
2006 Long-Term Stock Incentive Plan | Maximum	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Settlement of PBU's (percentage)	200.00%	200.00%

Equity_Compensation_Plans_Summ

Equity Compensation Plans (Summary of PBUs) (Details) (Unvested PBUs, USD $)	6 Months Ended
	Jun. 30, 2014
Unvested PBUs	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'
Unvested PBUs at December 31, 2013	1,065,734
Granted	280,171
Vested	-355,247	[1]
Forfeited	0
Unvested PBUs at June 30, 2014	990,658
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'
Fair Value per Unit, Unvested PBUs at December 31, 2013	$1.56
Fair Value per Unit, Granted	$7.34
Fair Value per Unit, Vested	$1.56	[1]
Fair value per unit, Forfeited	$0
Fair Value per Unit, Unvested PBUs at June 30, 2014	$3.19
[1]	The first tranche of the January 30, 2013 PBU grant vested on January 30, 2014 and settled at 200% based on the Company's share price appreciation compared to the peer group index.

Interest_Expense_Schedule_of_C

Interest Expense (Schedule of Components of Interest Expense) (Details) (USD $)	3 Months Ended				6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Interest Expense [Abstract]	'		'		'		'
Cash and accrued	$7,208		$2,962		$14,342		$3,862
Amortization of deferred financing costs	758	[1]	1,372	[1]	1,491	[1]	1,450	[1]
Capitalized interest	-1,054		-789		-2,030		-1,158
Total interest expense	6,912		3,545		13,803		4,154
Accretion of debt discount	$570		'		$1,100		'
[1]	The three and six months ended JuneB 30, 2014 includes $570,000 and $1.1 million, 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		6 Months Ended
In Thousands, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]	'	'	'	'
Net income attributable to common stockholders	$2,016	$51,836	$51	$47,250
Weighted average common shares outstanding basic (shares)	58,702,982	62,398,472	58,462,124	63,089,987
Weighted average common shares outstanding diluted (shares)	61,922,874	63,813,423	61,674,267	63,699,525
Basic (dollars per share)	$0.03	$0.83	$0	$0.75
Diluted (dollars per share)	$0.03	$0.81	$0	$0.74
Common shares excluded from denominator as anti-dilutive (shares)	0	770,200	0	2,216,045
Unvested restricted shares	'	'	'	'
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]	'	'	'	'
Incremental Shares	2,514,542	1,151,451	2,563,673	607,974
Common shares excluded from denominator as anti-dilutive (shares)	0	0	0	1,308,507
Stock options	'	'	'	'
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]	'	'	'	'
Incremental Shares	112,232	1,564	106,499	1,564
Common shares excluded from denominator as anti-dilutive (shares)	0	770,200	0	859,156
Unvested PBUs	'	'	'	'
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]	'	'	'	'
Incremental Shares	593,118	261,936	541,971	0
Common shares excluded from denominator as anti-dilutive (shares)	0	0	0	48,382

Commitments_And_Contingencies_

Commitments And Contingencies (Narrative) (Details) (USD $)	0 Months Ended		6 Months Ended			0 Months Ended
	Dec. 17, 2010	Apr. 22, 2014	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Jun. 17, 2014	Aug. 07, 2013
	Gastar Exploration Ltd vs US Speciality Ins Co and Axis Ins Co	Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania	Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania	Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania	Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania	Gastar Exploration USA	Gastar Exploration USA
		well	well	Mcfe	Marshall County, West Virginia	Gastar Exploration USA Inc v Williams Ohio Valley Midstream LLC	Gastar Exploration USA Inc v Williams Ohio Valley Midstream LLC
			acre		acre
			Mcfe
Loss Contingencies [Line Items]	'	'	'	'	'	'	'
Counterclaim for damages	'	'	'	'	'	'	$612,000
Settlement aggregate amount	21,200,000	'	'	'	'	8,600,000	'
Combined coverage limits under directors and officers insurance	$20,000,000	'	'	'	'	'	'
Number of wells drilled in which Eagle Natrium LLC is seeking to enjoin	'	3	'	'	'	'	'
Gross acres (acres)	'	'	3,300	'	13,700	'	'
Gross horizontal wells drilled without incident	'	'	15	'	'	'	'
Proved undeveloped well locations, proved undeveloped reserves (Bcfe)	'	'	'	87,700	'	'	'
Percentage of total proved reserves	'	'	'	19.00%	'	'	'

Statement_Of_Cash_Flows_Supple2

Statement Of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Supplemental Cash Flow Information [Abstract]	'	'
Cash paid for interest, net of capitalized amounts	$14,469	$1,840
Non-cash transactions:	'	'
Capital expenditures excluded from accounts payable and accrued drilling costs	655	-1,031
Capital expenditures excluded from accounts receivable	4,077	0
Capital expenditures excluded from prepaid expenses	51	0
Asset retirement obligation included in oil and natural gas properties	45	1,775
Asset retirement obligation sold	0	-362
Application of advances to operators	19,926	7,728
Other	($3)	$157