Gastar Exploration (GST) 10-Q 5 May 16 2016 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 02, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Entity Registrant Name	Gastar Exploration Inc.
Trading Symbol	GST
Entity Central Index Key	1,431,372
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		81,712,298

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 26,950	$ 50,074
Accounts receivable, net of allowance for doubtful accounts of $0, respectively	11,905	14,302
Commodity derivative contracts	7,767	15,534
Prepaid expenses	4,956	5,056
Total current assets	51,578	84,966
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	103,221	92,609
Proved properties	1,292,089	1,286,373
Total oil and natural gas properties	1,395,310	1,378,982
Furniture and equipment	3,072	3,068
Total property, plant and equipment	1,398,382	1,382,050
Accumulated depreciation, depletion and amortization	(1,115,342)	(1,053,116)
Total property, plant and equipment, net	283,040	328,934
OTHER ASSETS:
Commodity derivative contracts	8,309	9,335
Deferred charges, net	1,667	985
Advances to operators and other assets	629	331
Other	4,944	4,944
Total other assets	15,549	15,595
TOTAL ASSETS	350,167	429,495
CURRENT LIABILITIES:
Accounts payable	6,942	2,029
Revenue payable	9,812	5,985
Accrued interest	10,660	3,730
Accrued drilling and operating costs	2,102	2,010
Advances from non-operators	147	167
Commodity derivative premium payable	1,723	3,194
Asset retirement obligation	89	89
Other accrued liabilities	6,053	6,764
Total current liabilities	37,528	23,968
LONG-TERM LIABILITIES:
Long-term debt	496,927	516,476
Commodity derivative contracts	0	451
Commodity derivative premium payable	2,339	2,788
Asset retirement obligation	6,111	5,997
Total long-term liabilities	$ 505,377	$ 525,712
Commitments and contingencies (Note 11)
STOCKHOLDERS’ EQUITY:
Common stock	$ 82	$ 80
Additional paid-in capital	572,867	571,947
Accumulated deficit	(765,749)	(692,274)
Total stockholders’ equity	(192,738)	(120,185)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	350,167	429,495
Series A Preferred Stock
STOCKHOLDERS’ EQUITY:
Preferred stock	41	41
Series B Preferred Stock
STOCKHOLDERS’ EQUITY:
Preferred stock	$ 21	$ 21

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accounts receivable, net of allowance for doubtful accounts	$ 0	$ 0
Preferred stock, shares authorized	40,000,000	40,000,000
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	81,837,274	80,024,218
Common stock, shares outstanding	81,837,274	80,024,218
Series A Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares issued	4,045,000	4,045,000
Preferred stock, shares outstanding	4,045,000	4,045,000
Liquidation Preference	$ 25	$ 25
Series B Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares issued	2,140,000	2,140,000
Preferred stock, shares outstanding	2,140,000	2,140,000
Liquidation Preference	$ 25	$ 25

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
REVENUES:
Oil and condensate	$ 8,813	$ 15,353
Natural gas	4,018	6,700
NGLs	1,695	2,096
Total oil, condensate, natural gas and NGLs revenues	14,526	24,149
Gain on commodity derivatives contracts	285	10,223
Total revenues	14,811	34,372
EXPENSES:
Production taxes	705	840
Lease operating expenses	6,079	6,019
Transportation, treating and gathering	613	497
Depreciation, depletion and amortization	13,729	14,471
Impairment of oil and natural gas properties	48,497	0
Accretion of asset retirement obligation	105	125
General and administrative expense	5,675	4,248
Total expenses	75,403	26,200
(LOSS) INCOME FROM OPERATIONS	(60,592)	8,172
OTHER INCOME (EXPENSE):
Interest expense	(9,298)	(7,561)
Investment income and other	33	3
(LOSS) INCOME BEFORE PROVISION FOR INCOME TAXES	(69,857)	614
Provision for income taxes	0	0
NET (LOSS) INCOME	(69,857)	614
Dividends on preferred stock	(3,618)	(3,618)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (73,475)	$ (3,004)
NET LOSS PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic (in dollars per share)	$ (0.93)	$ (0.04)
Diluted (in dollars per share)	$ (0.93)	$ (0.04)
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic (shares)	78,788,133	77,114,826
Diluted (shares)	78,788,133	77,114,826

Condensed Consolidated Stateme5

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income		$ (69,857)	$ 614
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		13,729	14,471
Impairment of oil and natural gas properties		48,497	0
Stock-based compensation		1,633	1,526
Total gain on commodity derivatives contracts		(285)	(10,223)
Cash settlements of matured commodity derivatives contracts, net		8,158	5,277
Amortization of deferred financing costs	[1]	990	822
Accretion of asset retirement obligation		105	125
Changes in operating assets and liabilities:
Accounts receivable		636	14,279
Prepaid expenses		100	275
Accounts payable and accrued liabilities		11,475	5,957
Net cash provided by operating activities		15,181	33,123
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties		(12,825)	(46,121)
Advances to operators		(69)	(1,753)
Acquisition of oil and natural gas properties		127	0
Proceeds from sale of oil and natural gas properties		0	2,008
Payments to non-operators		(20)	(795)
Purchase of furniture and equipment		(4)	(3)
Net cash used in investing activities		(12,791)	(46,664)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility		0	25,000
Repayment of revolving credit facility		(20,370)	(5,000)
Dividends on preferred stock		(3,618)	(3,618)
Deferred financing charges		(815)	(281)
Tax withholding related to restricted stock and performance based unit award vestings		(711)	(1,425)
Net cash (used in) provided by financing activities		(25,514)	14,676
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(23,124)	1,135
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		50,074	11,008
CASH AND CASH EQUIVALENTS, END OF PERIOD		$ 26,950	$ 12,143
[1]	The three months ended March 31, 2016 and 2015 includes $677,000 and $613,000, respectively, of debt discount accretion related to the Notes.

Description of Business

Description of Business	3 Months Ended
	Mar. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Description of Business	1. Description of Business Gastar Exploration Inc. (the “Company” or “Gastar”) is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Gastar’s principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, Gastar has developed and is drilling other prospective formations on the same acreage, primarily the Meramec Shale (Middle Mississippi Lime), while Gastar plans to also test the Woodford Shale, along with emerging prospective plays in the shallow Oswego formation and in the Osage formation, a deeper bench of the Mississippi Lime located below the Meramec as well as the proven Hunton Limestone horizontal oil play. These formations comprise what is commonly referred to as the STACK Play. In West Virginia, Gastar developed liquids-rich natural gas in the Marcellus Shale and drilled and completed two successful dry gas Utica Shale/Point Pleasant wells on its acreage. On April 8, 2016, Gastar sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for an adjusted sales price of $76.6 million, subject to certain additional adjustments, with an effective date of January 1, 2016 (the “Appalachian Basin Sale”). The Appalachian Basin Sale will be considered a significant disposition, thus resulting in changes to the Company’s financial position, statement of operations and cash flows on a go-forward basis.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. 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, 2015 (the “2015 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2015 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material item included in those notes has changed except as a result of normal transactions in the interim or as disclosed within this report. The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2015 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 2015 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 months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate. On April 8, 2016, the Company completed the Appalachian Basin Sale. After certain adjustments (including an adjustment for the assumption by the buyer of approximately $2.8 million in revenue suspense liabilities), cash proceeds from the Appalachian Basin Sale were approximately $76.6 million, subject to certain additional adjustments. In connection with the completion of the Appalachian Basin Sale, the Company used the cash proceeds and other funds to reduce the outstanding borrowings under its revolving credit facility by $80.0 million. Recent Accounting Developments The following recently issued accounting pronouncements may impact the Company in future periods: Compensation – Stock Compensation. In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Leases. In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Income Taxes. In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards (IFRS). IAS 1, . This guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period and can be applied either prospectively or retrospectively to all periods presented. The Company does not expect the adoption of this guidance to materially impact its consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability, other than those costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, similar to the presentation for debt discounts and premiums, instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. This guidance was effective for the Company on January 1, 2016. The Company’s adoption of this guidance was applied retrospectively and did not have a material impact on the Company’s consolidated financial statements. Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following the date of issuance of annual and interim financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods ending after December 15, 2016 and for annual periods and interim periods thereafter. Earlier adoption is permitted, but the Company has not elected to adopt the updated guidance early. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue, which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, “Revenue Recognition,” and most industry-specific guidance. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018 and such proposal was subsequently adopted by the FASB in August 2015. The Company is evaluating the new guidance and has not yet determined the impact this new standard may have on its consolidated financial statements or decided upon its method of adoption.

Property, Plant and Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2016
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	3. 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., located in the states of Oklahoma, Pennsylvania and West Virginia. On April 8, 2016, the Company sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin. The following table summarizes the components of unproved properties excluded from amortization at the dates indicated: March 31, 2016 December 31, 2015 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 3,155 $ 1,533 Acreage acquisition costs 90,965 82,560 Capitalized interest 9,101 8,516 Total unproved properties excluded from amortization $ 103,221 $ 92,609 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 (discounted at 10% per annum) of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that the Company's capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling at the end of the reported period, the excess must be written off to expense for such period. 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 is determined using a mandatory trailing 12-month unweighted arithmetic average of the first-day-of-the-month commodities pricing and costs in effect at the end of the period, each of which are held constant indefinitely (absent specific contracts with respect to future prices and costs) with respect to valuing future net cash flows from proved reserves for this purpose. The 12-month unweighted arithmetic average of the first-day-of-the-month commodities prices are adjusted for basis and quality differentials in determining the present value of the proved 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: 2016 Total Year to Date Impairment March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.40 West Texas Intermediate oil price (per Bbl) (1) $ 46.26 Impairment recorded (pre-tax) (in thousands) $ 48,497 $ 48,497 2015 Total Year to Date Impairment March 31 Henry Hub natural gas price (per MMBtu) (1) $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 82.72 Impairment recorded (pre-tax) (in thousands) $ — $ — (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 spot natural gas prices and West Texas Intermediate spot oil prices. The Company could potentially incur further ceiling test impairments in 2016 assuming commodities prices do not increase. While it is difficult to project future impairment charges in light of numerous variables involved, the following analysis using basic assumptions is provided to illustrate the impact of lower commodities pricing on impairment charges and proved reserves volumes. The historical 12-month unweighted average first-day-of-the-month benchmark price applicable to proved reserves reported under SEC rules on April 1, 2016 decreased to $2.34 per MMbtu for natural gas and $45.16 per barrel for crude oil. The Company’s estimated proved reserve volumes were 55.9 MMBoe at December 31, 2015 using the SEC-mandated 12-month average benchmark pricing at such date. If such reserves estimates were made using the further reduced 12-month average benchmark prices as of April 1, 2016 as described in the foregoing paragraph and without regard to cost savings, reserve additions or other further revisions to reserves other than as a result of such pricing changes, the Company’s internally estimated proved reserves as of December 31, 2015, excluding the impact of recent sales, would decrease primarily as a result of the loss of proved undeveloped locations and tail-end estimated future production volumes which would not be economically producible at such lower prices. The Company’s proved reserves estimates and their estimated discounted value and standardized measure will also be impacted by changes in lease operating costs, future development costs, production, exploration and development activities. Appalachian Basin Sale On February 19, 2016, the Company entered into an agreement to sell substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for $80.0 million, subject to customary closing adjustments. Pursuant to the agreement, on April 8, 2016, the Company completed the Appalachian Basin Sale for an adjusted sales price of $76.6 million, subject to certain additional adjustments. Appalachian Basin Sale Pro Forma Operating Results The following unaudited pro forma results for the three months ended March 31, 2016 and 2015 show the effect on the Company's consolidated results of operations as if the Appalachian Basin Sale had occurred at the beginning of the periods presented. The pro forma results are the result of excluding from the statement of operations of the Company the revenues and direct operating expenses for the properties divested adjusted for (1) the reduction in ARO liabilities and accretion expense for the properties divested, (2) the reduction in depreciation, depletion and amortization expense as a result of the divestiture and (3) the reduction in interest expense as a result of the pay down of debt under the Revolving Credit Facility in conjunction with the closing of the Appalachian Basin Sale. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Three Months Ended March 31, 2016 2015 (in thousands, except (Unaudited) Revenues $ 11,621 $ 28,152 Net Loss $ (68,647 ) $ (6,969 ) Loss per share: Basic $ (0.87 ) $ (0.09 ) Diluted $ (0.87 ) $ (0.09 ) 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 Appalachian Basin Sale occurred as presented. In addition, future results may vary significantly from the results reflected in such pro forma information. Husky Acquisition On December 16, 2015, the Company completed the acquisition of additional working and net revenue interests in 103 gross (10.2 net) producing wells and certain undeveloped acreage in the STACK and Hunton Limestone formations in its existing AMI from its AMI co-participant Husky Ventures, Inc. (“Husky”), Silverstar of Nevada, Inc., Maximus Exploration, LLC and Atwood Acquisitions, LLC for an adjusted purchase price of approximately $42.1 million, reflecting adjustment for an acquisition effective date of July 1, 2015 and which includes a $4.9 million deposit into escrow pending the resolution of title defects by the seller and the purchase of overrides recorded to other assets at March 31, 2016, and the conveyance of approximately 11,000 net non-core, non-producing acres in Blaine, Major and Kingfisher Counties, Oklahoma to the sellers, subject to certain adjustments and customary closing conditions (the “Husky Acquisition”). In connection with the acquisition, the AMI participation agreements with the Company’s AMI co-participant were dissolved. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred a total of $1.3 million of transaction and integration costs associated with the acquisition since closing and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 5, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the Husky Acquisition assets resulted in a fair market valuation of $44.6 million. As the fair market valuation varied less than 6% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation. Husky Acquisition Pro Forma Operating Results The following unaudited pro forma results for the three months ended March 31, 2015 show the effect on the Company's consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) 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 Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Three Months Ended March 31, 2015 (in thousands, except (Unaudited) Revenues $ 36,831 Net Loss $ (1,882 ) Loss per share: Basic $ (0.02 ) Diluted $ (0.02 ) 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 Husky Acquisition 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. Atinum Participation Agreement In September 2010, the Company entered into a participation agreement (the “Atinum Participation Agreement”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum” and, together with the Company, the “Atinum co-participants), a Korean investment firm. Pursuant to which the Company ultimately assigned to an affiliate of Atinum, for total consideration of $70.0 million, a 50% working interest in certain undeveloped acreage and wells. Effective June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Prior to the Appalachian Basin Sale, within this AMI, the Company acted as operator and was obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum paid the Company on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million. The Atinum co-participants pursued an initial three-year development program that called for the drilling of a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, the Atinum co-participants agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 gross wells to 51 gross wells. At March 31, 2016, 74 gross operated horizontal Marcellus Shale wells and two gross operated horizontal Utica Shale/Point Pleasant wells were capable of production under the Atinum Participation Agreement. The Atinum Participation Agreement expired on November 1, 2015. On April 8, 2016, the Company sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for an adjusted sales price of $76.6 million, subject to certain additional adjustments, reflecting an effective date of January 1, 2016.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	4. Long-Term Debt Second Amended and Restated Revolving Credit Facility On June 7, 2013, the Company entered into the Second Amended and Restated Credit Agreement among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). At the Company's election, borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent, (ii) the federal funds rate plus 50 basis points and (iii) LIBOR plus 1.0%. The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the borrowing base and subject to adjustments based on the Company's leverage ratio. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity of November 14, 2017. The Revolving Credit Facility will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees are secured by a first priority lien on certain domestic oil and natural gas properties currently owned by or later acquired by the Company and its subsidiaries, excluding de minimis value properties as determined by the lender. The Revolving Credit Facility is secured by a first priority pledge of the capital stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of any foreign subsidiary of the Company. The Revolving Credit Facility contains various covenants, including, among others: · Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments; · Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0, as adjusted; · Maintenance of a maximum ratio of net indebtedness to EBITDA of not greater than 4.0 to 1.0, subject to the modifications in Amendment No. 5 set forth below; and · Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0, subject to the modifications in Amendment No. 5 set forth below. All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including, among others: · Failure to make payments; · Non-performance of covenants and obligations continuing beyond any applicable grace period; and · The occurrence of a change in control of the Company, as defined under the Revolving Credit Facility. On March 9, 2015, the Company, together with the parties thereto, entered into a Master Assignment, Agreement and Amendment No. 5 to Second Amended and Restated Credit Agreement (“Amendment No. 5”). Amendment No. 5 amended the Revolving Credit Facility to, among other things, (i) increase the borrowing base from $145.0 million to $200.0 million, (ii) adjust the total leverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to September 30, 2016, to 5.25 to 1.00; for the fiscal quarter ending on September 30, 2016, to 5.00 to 1.00; for the fiscal quarter ending on December 31, 2016, to 4.75 to 1.00; for the fiscal quarter ending on March 31, 2017, to 4.25 to 1.00; and for each fiscal quarter ending on or after June 30, 2017, to 4.00 to 1.00, (iii) adjust the interest coverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to March 31, 2016, to 2.00 to 1.00 and for each fiscal quarter ending on or after March 31, 2016, to 2.50 to 1.00, and (iv) add the senior secured leverage ratio covenant, such ratio not to exceed, (a) for each fiscal quarter ending on or after March 31, 2015 but prior to June 30, 2016, 2.25 to 1.00 and (b) for each fiscal quarter ending on or after June 30, 2016, 2.00 to 1.00 provided that this senior secured leverage ratio shall cease to apply commencing with the first fiscal quarter end occurring after June 30, 2016 for which the total leverage ratio is equal to or less than 4.00 to 1.00. On December 22, 2015, the Company, together with the parties thereto, entered into Amendment No. 6 to Second Amended and Restated Credit Agreement (“Amendment No. 6”). Amendment No. 6 amended the Revolving Credit Facility to permit the Company to exchange its outstanding Notes constituting Second Lien Debt under the Revolving Credit Facility for equity interests in the Company. On January 29, 2016, the Company, together with the parties thereto, entered into Limited Waiver and Amendment No. 7 to Second Amended and Restated Credit Agreement (“Amendment No. 7”). Pursuant to Amendment No. 7, the Company obtained (i) a waiver until March 10, 2016 of any potential defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility and (ii) a permanent waiver of any defaults of the restricted payment covenant under the Revolving Credit Facility resulting from (a) cash distributions paid on December 31, 2015 in respect of its Series A Preferred Stock and its Series B Preferred Stock and (b) the issuance on January 28, 2016, as a dividend on the Company’ common stock, of the right to purchase Series C Junior Participating Preferred Stock pursuant to the Company’s Rights Agreement dated as of January 18, 2016 as part of the Company’s previously disclosed tax benefits preservation plan. The Revolving Credit Facility was also amended to permit the Company to make dividends and distributions of preferred equity interests or rights to purchase certain preferred equity interests. The entry into Amendment No. 7 permitted the Company to pay monthly cash dividends on its Series A Preferred Stock and its Series B Preferred Stock on February 1, 2016. On March 9, 2016, the Company, together with the parties thereto, entered into Waiver and Amendment No. 8 to Second Amended and Restated Credit Agreement (“Amendment No. 8”). Pursuant to Amendment No. 8, the Company obtained the following relief with respect to its financial covenant compliance: (i) a permanent waiver of the defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility; (ii) relief from compliance with its leverage ratio through the fiscal quarter ending March 31, 2017, but the Company must maintain a maximum leverage ratio of not greater than 4.0 to 1.0 for each fiscal quarter ending on or after June 17, 2017; (iii) an adjustment to the interest coverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 1.10 to 1.00 and for each fiscal quarter ending on or after June 30, 2017 to 2.50 to 1.00; and (iv) an adjustment to its senior secured leverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 2.50 to 1.00 provided that during such period the Company may subtract all cash on hand in calculating the senior secured leverage ratio for such periods and for each fiscal quarter ending on or after June 30, 2017, to 2.00 to 1.00 provided that during such period the Company may only subtract up to $5 million of cash on hand in calculating the senior secured leverage ratio for such periods As consideration for the financial covenant relief provided for in Amendment No. 8, the Revolving Credit Facility was also amended to, among other things: (i) set the interest margin at (a) 4.0% per annum for Eurodollar rate borrowings and (b) 3.0% per annum for borrowings based on the reference rate; (ii) reduce the borrowing base from $200.0 million to $180.0 million until the earlier of the closing of the Appalachian Basin Sale or April 10, 2016, at which point the borrowing base would automatically be reduced to $100.0 million and require borrowings in excess of such amount be repaid immediately; (iii) require additional automatic reductions of the borrowing base in connection with asset sales in excess of $5.0 million or the termination of any hedge agreements governing hedges with a settlement date on or after July 1, 2016; (iv) provide for an additional interim borrowing base redetermination in August 2016; (v) require the consent of the lenders to any asset sales in excess of $5.0 million; and (vi) restrict the Company after March 2016 from making any distributions or paying any cash dividends to the holders of its preferred equity, including its outstanding shares of Series A Preferred Stock and Series B Preferred Stock. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year, although an additional scheduled redetermination will occur in August 2016, as set forth in Amendment No. 8. The Company and its lenders may each request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. At March 31, 2016, the Revolving Credit Facility had a borrowing base of $180.0 million, with $179.6 million of borrowings outstanding and $370,000 of letters of credit outstanding. In connection with Amendment No. 8 and in conjunction with the closing of the Appalachian Basin Sale, the borrowing base was reduced from $180.0 million to $100.0 million on April 8, 2016. As of May 2, 2016, there were $99.6 million of borrowings outstanding and $370,000 of letters of credit issued under the Revolving Credit Facility. 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 indenture pursuant to which the Company's senior secured notes are issued (as discussed below in “Senior Secured Notes”). At March 31, 2016, the Company was in compliance with all financial covenants under the Revolving Credit Facility. Senior Secured Notes The Company has $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Notes”) outstanding under an indenture (the “Indenture”) by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year. The Notes mature on May 15, 2018. In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require the Company to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. The Notes will be guaranteed, jointly and severally, on a senior secured basis by certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of the Company's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of the Company's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also 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: · Incur additional indebtedness or refinance existing indebtedness; · 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, including securing additional indebtedness or refinancing existing indebtedness; · 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. Covenants in the Indenture also limit the Company’s ability to borrow on a first priority lien secured basis, including its ability to refinance the full amount of currently outstanding borrowings under its Revolving Credit Facility or to reborrow on such facility in the event current borrowings thereunder are paid down. These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture. A summary of the Notes balance for the periods indicated is as follows: March 31, 2016 December 31, 2015 (in thousands) Notes, principal balance $ 325,000 $ 325,000 Less: Unamortized discounts (6,474 ) (7,151 ) Deferred financing costs (1,229 ) (1,373 ) Notes, net $ 317,297 $ 316,476

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	5. Fair Value Measurements The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties or estimated market data based on area transactions, which are Level 3 inputs. For the three months ended March 31, 2016 and 2015, due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, management’s evaluation of unproved properties resulted in impairment and the Company reclassified an immaterial amount of costs from unproved to proved properties for each period. As no other fair value measurements are required to be recognized on a non-recurring basis at March 31, 2016, no additional disclosures are provided at March 31, 2016. 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 2016 and 2015 periods. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015: Fair value as of March 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 26,950 $ — $ — $ 26,950 Commodity derivative contracts — — 16,076 16,076 Liabilities: Commodity derivative contracts — — - - Total $ 26,950 $ — $ 16,076 $ 43,026 Fair value as of December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 50,074 $ — $ — $ 50,074 Commodity derivative contracts — — 24,869 24,869 Liabilities: Commodity derivative contracts — — (451 ) (451 ) Total $ 50,074 $ - $ 24,418 $ 74,492 The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2016 and 2015. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at March 31, 2016 and 2015. Three Months Ended March 31, 2016 2015 (in thousands) Balance at beginning of period $ 24,418 $ 27,502 Total gains included in earnings 285 10,223 Purchases — 866 Issuances — (186 ) Settlements (1) (8,627 ) (6,582 ) Balance at end of period $ 16,076 $ 31,823 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 March 31, 2016 and 2015 $ (6,497 ) $ 4,252 (1) Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations. At March 31, 2016, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at March 31, 2016 was $388.4 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximates the current market rate (Level 2). The Company has consistently applied the valuation techniques discussed above in all periods presented. The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 6, “Derivative Instruments and Hedging Activity.”

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activity	3 Months Ended
	Mar. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activity	6. 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 March 31, 2016 and 2015, the Company reported a loss of $6.5 million and a gain of $4.3 million, respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts still held at March 31, 2016 and 2015. As of March 31, 2016, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume(1) Total of Notional Volume Floor (Long) Short Put Ceiling (Short) (in Bbls) 2016 (2) Costless three-way collar 250 38,250 $ 85.00 $ 65.00 $ 95.10 2016 (2) Costless three-way collar 330 50,490 $ 80.00 $ 65.00 $ 97.35 2016 (2) Costless three-way collar 450 68,850 $ 57.50 $ 42.50 $ 80.00 2016 (2) Put spread 550 84,150 $ 85.00 $ 65.00 $ — 2016 (2) Put spread 300 45,900 $ 85.50 $ 65.50 $ — 2017 Costless three-way collar 280 102,200 $ 80.00 $ 65.00 $ 97.25 2017 Costless three-way collar 250 91,250 $ 80.00 $ 60.00 $ 98.70 2017 Costless three-way collar 200 73,000 $ 60.00 $ 42.50 $ 85.00 2017 Put spread 500 182,500 $ 82.00 $ 62.00 $ — 2017 Costless three-way collar 200 73,000 $ 57.50 $ 42.50 $ 76.13 2018 (3) Put spread 425 103,275 $ 80.00 $ 60.00 $ — (1) Crude volumes hedged include oil, condensate and certain components of our NGLs production. (2) For the period August to December 2016. (3) For the period January to August 2018. As of March 31, 2016, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Call (Long) Ceiling (Short) (in MMBtus) 2016 (1) Producer three-way 2,500 230,000 $ — $ 3.00 $ 2.25 $ — $ 3.65 2016 (2) Producer three-way 2,000 306,000 $ — $ 4.00 $ 3.25 $ — $ 4.58 2016 (2) Producer three-way 5,000 765,000 $ — $ 3.40 $ 2.65 $ — $ 4.10 2017 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 2018 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 (1) For the period August to October 2016. (2) For the period August to December 2016. As of March 31, 2016, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price (in Bbls) 2016 (1) Fixed price swap 500 76,500 $ 20.79 _______________ (1) For the period August to December 2016. As of March 31, 2016, all of the Company’s economic derivative hedge positions were with 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 has deferred the payment of certain put premiums for the production month period August 2016 through December 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. The following table provides information regarding the deferred put premium liabilities for the periods indicated: March 31, 2016 December 31, 2015 (in thousands) Current commodity derivative put premium payable $ 1,723 $ 3,194 Long-term commodity derivative put premium payable 2,339 2,788 Total unamortized put premium liabilities $ 4,062 $ 5,982 For the Three Months Ended March 31, 2016 (in thousands) Put premium liabilities, beginning balance $ 5,982 Amortization of put premium liabilities — Settlement of put premium liabilities (1,920 ) Put premium liabilities, ending balance $ 4,062 The following table provides information regarding the amortization of the deferred put premium liabilities by year as of March 31, 2016: Amortization (in thousands) August to December 2016 $ 1,275 January to December 2017 1,819 January to August 2018 968 Total unamortized put premium liabilities $ 4,062 Additional Disclosures about Derivative Instruments and Hedging Activities The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value Balance Sheet Location March 31, 2016 December 31, 2015 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 7,767 $ 15,534 Commodity derivative contracts Other assets 8,309 9,335 Commodity derivative contracts Long-term liabilities — (451 ) Total derivatives not designated as hedging instruments $ 16,076 $ 24,418 Amount of Gain Recognized in Income on Derivatives For the Three Months Ended March 31, Location of Gain Recognized in Income on Derivatives 2016 2015 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Gain on commodity derivatives contracts $ 285 $ 10,223 Total $ 285 $ 10,223

Capital Stock

Capital Stock	3 Months Ended
	Mar. 31, 2016
Stockholders Equity Note [Abstract]
Capital Stock	7. Capital Stock Common Stock On May 7, 2015, the Company entered into an at-the-market issuance sales agreement with MLV & Co. LLC (the “Sales Agent”) to sell, from time to time through the Sales Agent, shares of the Company's common stock (the “ATM Program”). The shares will be issued pursuant to the Company's existing effective shelf registration statement on Form S-3, as amended (Registration No. 333-193832). The Company registered shares having an aggregate offering price of up to $50.0 million. To date, no shares have been sold through the ATM program. Stockholder Rights Agreement On January 18, 2016, the Company’s Board of Directors adopted a stockholder rights plan (the “Rights Agreement”) pursuant to which the Company declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on January 28, 2016. Each Right entitles the holder, subject to the terms of the Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $6.96, subject to certain adjustments. The purpose of the Rights Agreement is to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. The Rights generally become exercisable on the earlier of (i) ten business days after any person or group obtains beneficial ownership of 4.9% of the Company’s outstanding common stock (an “Acquiring Person”) or (ii) ten business days after commencement of a tender or exchange offer resulting in any person or group becoming an Acquiring Person. The exercise price payable, and the number of shares of Series C Preferred Stock or other securities or property issuable, upon exercise of the Rights are subject to adjustment from time to time to prevent dilution. In the event that, after a person or a group has become an Acquiring Person, the Company is acquired in a merger or other business combination transaction (or 50% or more of the Company’s assets or earning power are sold), proper provision will be made so that each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then-current exercise price of the Right, that number of shares of common stock of the acquiring company having a market value at the time of that transaction equal to two times the exercise price. The Company may redeem the Rights in whole, but not in part, at any time before a person or group becomes an Acquiring Person at a price of $0.001 per Right, subject to adjustment. At any time after any person or group becomes an Acquiring Person, the Company may generally exchange each Right in whole or in part at an exchange ratio of two shares of common stock per outstanding Right, subject to adjustment. The Rights will expire on January 18, 2019 unless terminated on an earlier date pursuant to the terms of the Rights Agreement. The Series C Preferred Stock is not redeemable by the Company and has certain voting rights and dividend and liquidation privileges. Preferred Stock Pursuant to the Company’s certificate of incorporation, the Company has 40,000,000 shares of preferred stock authorized. The Company has designated 10,000,000 of such shares to constitute its 8.625% Series A Cumulative Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 of such shares to constitute its 10.75% Series B Cumulative Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share. Series A Preferred Stock At March 31, 2016, there were 4,045,000 shares of the Series A Preferred Stock issued and outstanding with a $25.00 per share liquidation preference. The Series A Preferred Stock ranks senior to the Company's common stock and on parity with the Series B Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series A Preferred Stock is subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. The Series A Preferred Stock cannot be converted into common stock, but may be redeemed, at the Company’s option for $25.00 per share plus any accrued and unpaid dividends whether declared or not. There is no mandatory redemption of the Series A Preferred Stock. The Company paid cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three months ended March 31, 2016, the Company recognized dividend expense of $2.2 million for the Series A Preferred Stock. Effective March 9, 2016, the Revolving Credit Facility prohibits the payment of cash dividends on the Company’s preferred stock commencing April 2016. Accordingly, the Company did not declare or pay dividends on the Series A Preferred Stock in April 2016. Dividends on the Series A Preferred Stock will accumulate regardless of whether any such dividends are declared. If the Company fails to pay full cash dividends in four calendar quarters, whether consecutive or non-consecutive, and until accumulated dividends are paid in full for four calendar quarters with the last two calendar quarters’ dividends paid in cash, then (i) the fixed rate of Series A Preferred Stock each increases by 2.00%, (ii) the Company may be required to issue a dividend of common stock to pay accrued and unpaid dividends, if such dividends are not paid in cash, provided it has sufficient surplus to pay such a dividend under state law, and (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company. Under certain circumstances, “pay in kind” dividends of additional shares of Series A Preferred Stock may be payable in lieu of cash or common stock dividends. Series B Preferred Stock At March 31, 2016, there were 2,140,000 shares of the Series B Preferred Stock issued and outstanding with a $25.00 per share liquidation preference. The Series B Preferred Stock ranks senior to the Company’s common stock and on parity with the Series A Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock. Except upon a change in ownership or control, as defined in the Series B Preferred Stock certificate of designations of rights and preferences, 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 within 90 days of the occurrence of the change in control, 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 the Company's common stock based upon on an average common stock trading price then in effect but limited 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 paid cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the three months ended March 31, 2016, the Company recognized dividend expense of $1.4 million for the Series B Preferred Stock. Effective March 9, 2016, the Revolving Credit Facility prohibits the payment of cash dividends on the Company’s preferred stock commencing April 2016. Accordingly, the Company did not declare or pay dividends on the Series B Preferred Stock in April 2016. Dividends on the Series B Preferred Stock will accumulate regardless of whether any such dividends are declared. If the Company fails to pay full cash dividends in four calendar quarters, whether consecutive or non-consecutive, and until accumulated dividends are paid in full for four calendar quarters with the last two calendar quarters’ dividends paid in cash, then (i) the fixed rate of Series B Preferred Stock each increases by 2.00%, (ii) the Company may be required to issue a dividend of common stock to pay accrued and unpaid dividends, if such dividends are not paid in cash, provided it has sufficient surplus to pay such a dividend under state law, and (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company. Under certain circumstances, “pay in kind” dividends of additional shares of Series B Preferred Stock may be payable in lieu of cash or common stock dividends. 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 March 31, 2016 Other share issuances: Shares of restricted common stock granted 1,698,064 Shares of restricted common stock vested 1,439,840 Shares of common stock issued pursuant to PBUs vested, net of forfeitures 502,593 Shares of restricted common stock surrendered upon vesting/exercise (1) 386,241 Shares of restricted common stock forfeited 1,360 (1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period. On June 12, 2014, the Company's stockholders approved an amendment and restatement to the Gastar Exploration Inc. Long-Term Incentive Plan (the “LTIP”), effective April 24, 2014, to, among other things, increase the number of shares of common stock reserved for issuance under the LTIP by 3,000,000 shares of common stock. There were 996,980 shares of common stock available for issuance under the LTIP at March 31, 2016. Shares Reserved At March 31, 2016, the Company had 741,600 common shares reserved for the exercise of stock options.

Interest Expense

Interest Expense	3 Months Ended
	Mar. 31, 2016
Interest Expense [Abstract]
Interest Expense	8. Interest Expense The following table summarizes the components of interest expense for the periods indicated: For the Three Months Ended March 31, 2016 2015 (in thousands) Interest expense: Cash and accrued $ 8,907 $ 7,928 Amortization of deferred financing costs (1) 990 822 Capitalized interest (599 ) (1,189 ) Total interest expense $ 9,298 $ 7,561 (1) The three months ended March 31, 2016 and 2015 includes $677,000 and $613,000, respectively, of debt discount accretion related to the Notes.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	9. Income Taxes For the three months ended March 31, 2016 and 2015, respectively, the Company did not recognize a current income tax benefit or provision as the Company has a full valuation allowance against assets created by net operating losses generated. The Company believes it more likely than not that the assets will not be utilized.

Earnings per Share

Earnings per Share	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Earnings per Share	10. Earnings per Share In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. For the Three Months Ended March 31, 2016 2015 (in thousands, except per share and share data) Net loss attributable to common stockholders $ (73,475 ) $ (3,004 ) Weighted average common shares outstanding - basic 78,788,133 77,114,826 Incremental shares from unvested restricted shares — — Incremental shares from outstanding stock options — — Incremental shares from outstanding PBUs — — Weighted average common shares outstanding - diluted 78,788,133 77,114,826 Net loss per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (0.04 ) Diluted $ (0.93 ) $ (0.04 ) Common shares excluded from denominator as anti-dilutive: Unvested restricted shares 1,316,418 450,556 Stock options — — Unvested PBUs 1,484,907 373,325 Total 2,801,325 823,881

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	11. Commitments and Contingencies Litigation Gastar Exploration Ltd vs. U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No.2010-11236) District Court of Harris County, Texas 190th Judicial District . On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage is $20.0 million. The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012. The Company appealed the District Court ruling and on July 15, 2013, the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The insurers filed a motion for reconsideration in the Fourteenth Court of Appeals, which that court denied. The insurers then sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The insurers then filed in the Texas Supreme Court a motion for rehearing of their denied petition for review, which the court has denied. The case has now been remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of the portion of the Company's settlement of the ClassicStar Mare Lease Litigation that is covered by the insuring agreements. In October 2015, the Insurers sought a summary judgment based on one of the exclusions in the policy. The trial court denied their motion. After denying the insurers’ motion for summary judgment, the trial court, on February 17, 2016, entered a docket control order establishing the week of November 29, 2016 as the tentative week for the case to go to trial. The parties are currently engaged in discovery and the trial court has allowed limited deposition testimony from some of the former Mare Lease plaintiffs. Gastar Exploration Inc. v. Christopher McArthur (Cause No.: 2015-77605) 157th Judicial District Court, Harris County, Texas . On December 29, 2015, Gastar filed suit against Christopher McArthur (“McArthur”) in the District Court of Harris County, Texas. The lawsuit arises from a demand letter sent by McArthur to Gastar in which he claimed to be party to an agreement or contract with Gastar that entitled him to be paid $2.75 million for services rendered. In its lawsuit, Gastar denies that such an agreement or contract exists, that McArthur provided any services to Gastar or for Gastar’s benefit, and seeks a declaratory judgment that it did not enter into an agreement or contract with McArthur and that it does not owe any amounts to McArthur under the terms of any agreement or contract. Gastar also seeks to recover its attorneys’ fees. McArthur answered the lawsuit on February 8, 2016 by filing a general denial. 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 - Suppl

Statement of Cash Flows - Supplemental Information	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Statement Of Cash Flows - Supplemental Information	12. Statement of Cash Flows – Supplemental Information The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated: For the Three Months Ended March 31, 2016 2015 (in thousands) Cash paid for interest, net of capitalized amounts $ 1,378 $ (282 ) Non-cash transactions: Capital expenditures included in (excluded from) accounts payable and accrued drilling costs $ 3,538 $ (10,366 ) Capital expenditures included in accounts receivable $ 310 $ — Asset retirement obligation included in oil and natural gas properties $ 11 $ 77 Application of advances to operators $ (229 ) $ 8,457 Other $ 37 $ 23

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Basis of Accounting	The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2015 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 2015 Form 10-K.
Subsequent Events	Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate. On April 8, 2016, the Company completed the Appalachian Basin Sale. After certain adjustments (including an adjustment for the assumption by the buyer of approximately $2.8 million in revenue suspense liabilities), cash proceeds from the Appalachian Basin Sale were approximately $76.6 million, subject to certain additional adjustments. In connection with the completion of the Appalachian Basin Sale, the Company used the cash proceeds and other funds to reduce the outstanding borrowings under its revolving credit facility by $80.0 million.
Recent Accounting Developments	Recent Accounting Developments The following recently issued accounting pronouncements may impact the Company in future periods: Compensation – Stock Compensation. In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Leases. In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Income Taxes. In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards (IFRS). IAS 1, . This guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period and can be applied either prospectively or retrospectively to all periods presented. The Company does not expect the adoption of this guidance to materially impact its consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability, other than those costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, similar to the presentation for debt discounts and premiums, instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. This guidance was effective for the Company on January 1, 2016. The Company’s adoption of this guidance was applied retrospectively and did not have a material impact on the Company’s consolidated financial statements. Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following the date of issuance of annual and interim financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods ending after December 15, 2016 and for annual periods and interim periods thereafter. Earlier adoption is permitted, but the Company has not elected to adopt the updated guidance early. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue, which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, “Revenue Recognition,” and most industry-specific guidance. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018 and such proposal was subsequently adopted by the FASB in August 2015. The Company is evaluating the new guidance and has not yet determined the impact this new standard may have on its consolidated financial statements or decided upon its method of adoption.

Property, Plant And Equipment (

Property, Plant And Equipment (Tables)	3 Months Ended
	Mar. 31, 2016
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 at the dates indicated: March 31, 2016 December 31, 2015 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 3,155 $ 1,533 Acreage acquisition costs 90,965 82,560 Capitalized interest 9,101 8,516 Total unproved properties excluded from amortization $ 103,221 $ 92,609
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: 2016 Total Year to Date Impairment March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.40 West Texas Intermediate oil price (per Bbl) (1) $ 46.26 Impairment recorded (pre-tax) (in thousands) $ 48,497 $ 48,497 2015 Total Year to Date Impairment March 31 Henry Hub natural gas price (per MMBtu) (1) $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 82.72 Impairment recorded (pre-tax) (in thousands) $ — $ — (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 spot natural gas prices and West Texas Intermediate spot oil prices.
Husky Acquisition
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	The following unaudited pro forma results for the three months ended March 31, 2015 show the effect on the Company's consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) 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 Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Three Months Ended March 31, 2015 (in thousands, except (Unaudited) Revenues $ 36,831 Net Loss $ (1,882 ) Loss per share: Basic $ (0.02 ) Diluted $ (0.02 )
Appalachian Basin
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	The following unaudited pro forma results for the three months ended March 31, 2016 and 2015 show the effect on the Company's consolidated results of operations as if the Appalachian Basin Sale had occurred at the beginning of the periods presented. The pro forma results are the result of excluding from the statement of operations of the Company the revenues and direct operating expenses for the properties divested adjusted for (1) the reduction in ARO liabilities and accretion expense for the properties divested, (2) the reduction in depreciation, depletion and amortization expense as a result of the divestiture and (3) the reduction in interest expense as a result of the pay down of debt under the Revolving Credit Facility in conjunction with the closing of the Appalachian Basin Sale. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Three Months Ended March 31, 2016 2015 (in thousands, except (Unaudited) Revenues $ 11,621 $ 28,152 Net Loss $ (68,647 ) $ (6,969 ) Loss per share: Basic $ (0.87 ) $ (0.09 ) Diluted $ (0.87 ) $ (0.09 )

Long-Term (Tables)

Long-Term (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Summary of Notes Balance	A summary of the Notes balance for the periods indicated is as follows: March 31, 2016 December 31, 2015 (in thousands) Notes, principal balance $ 325,000 $ 325,000 Less: Unamortized discounts (6,474 ) (7,151 ) Deferred financing costs (1,229 ) (1,373 ) Notes, net $ 317,297 $ 316,476

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring and Nonrecurring	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015: Fair value as of March 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 26,950 $ — $ — $ 26,950 Commodity derivative contracts — — 16,076 16,076 Liabilities: Commodity derivative contracts — — - - Total $ 26,950 $ — $ 16,076 $ 43,026 Fair value as of December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 50,074 $ — $ — $ 50,074 Commodity derivative contracts — — 24,869 24,869 Liabilities: Commodity derivative contracts — — (451 ) (451 ) Total $ 50,074 $ - $ 24,418 $ 74,492
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2016 and 2015. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at March 31, 2016 and 2015. Three Months Ended March 31, 2016 2015 (in thousands) Balance at beginning of period $ 24,418 $ 27,502 Total gains included in earnings 285 10,223 Purchases — 866 Issuances — (186 ) Settlements (1) (8,627 ) (6,582 ) Balance at end of period $ 16,076 $ 31,823 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 March 31, 2016 and 2015 $ (6,497 ) $ 4,252 (1) Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

Derivative Instruments and He22

Derivative Instruments and Hedging Activity (Tables)	3 Months Ended
	Mar. 31, 2016
Summary of Information Regarding Deferred Put Premium Liabilities	The following table provides information regarding the deferred put premium liabilities for the periods indicated: March 31, 2016 December 31, 2015 (in thousands) Current commodity derivative put premium payable $ 1,723 $ 3,194 Long-term commodity derivative put premium payable 2,339 2,788 Total unamortized put premium liabilities $ 4,062 $ 5,982 For the Three Months Ended March 31, 2016 (in thousands) Put premium liabilities, beginning balance $ 5,982 Amortization of put premium liabilities — Settlement of put premium liabilities (1,920 ) Put premium liabilities, ending balance $ 4,062
Summary of Amortization of Deferred Put Premium Liabilities	The following table provides information regarding the amortization of the deferred put premium liabilities by year as of March 31, 2016: Amortization (in thousands) August to December 2016 $ 1,275 January to December 2017 1,819 January to August 2018 968 Total unamortized put premium liabilities $ 4,062
Summary of Information on the Location and Amounts of Derivative Fair Values and Derivative Gains and Losses	The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value Balance Sheet Location March 31, 2016 December 31, 2015 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 7,767 $ 15,534 Commodity derivative contracts Other assets 8,309 9,335 Commodity derivative contracts Long-term liabilities — (451 ) Total derivatives not designated as hedging instruments $ 16,076 $ 24,418 Amount of Gain Recognized in Income on Derivatives For the Three Months Ended March 31, Location of Gain Recognized in Income on Derivatives 2016 2015 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Gain on commodity derivatives contracts $ 285 $ 10,223 Total $ 285 $ 10,223
Natural Gas
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of March 31, 2016, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Call (Long) Ceiling (Short) (in MMBtus) 2016 (1) Producer three-way 2,500 230,000 $ — $ 3.00 $ 2.25 $ — $ 3.65 2016 (2) Producer three-way 2,000 306,000 $ — $ 4.00 $ 3.25 $ — $ 4.58 2016 (2) Producer three-way 5,000 765,000 $ — $ 3.40 $ 2.65 $ — $ 4.10 2017 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 2018 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 (1) For the period August to October 2016. (2) For the period August to December 2016.
Natural Gas Liquids
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of March 31, 2016, the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price (in Bbls) 2016 (1) Fixed price swap 500 76,500 $ 20.79 _______________ (1) For the period August to December 2016.
Crude Oil
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of March 31, 2016, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume(1) Total of Notional Volume Floor (Long) Short Put Ceiling (Short) (in Bbls) 2016 (2) Costless three-way collar 250 38,250 $ 85.00 $ 65.00 $ 95.10 2016 (2) Costless three-way collar 330 50,490 $ 80.00 $ 65.00 $ 97.35 2016 (2) Costless three-way collar 450 68,850 $ 57.50 $ 42.50 $ 80.00 2016 (2) Put spread 550 84,150 $ 85.00 $ 65.00 $ — 2016 (2) Put spread 300 45,900 $ 85.50 $ 65.50 $ — 2017 Costless three-way collar 280 102,200 $ 80.00 $ 65.00 $ 97.25 2017 Costless three-way collar 250 91,250 $ 80.00 $ 60.00 $ 98.70 2017 Costless three-way collar 200 73,000 $ 60.00 $ 42.50 $ 85.00 2017 Put spread 500 182,500 $ 82.00 $ 62.00 $ — 2017 Costless three-way collar 200 73,000 $ 57.50 $ 42.50 $ 76.13 2018 (3) Put spread 425 103,275 $ 80.00 $ 60.00 $ — (1) Crude volumes hedged include oil, condensate and certain components of our NGLs production. (2) For the period August to December 2016. (3) For the period January to August 2018.

Capital Stock (Tables)

Capital Stock (Tables)	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 Other share issuances: Shares of restricted common stock granted 1,698,064 Shares of restricted common stock vested 1,439,840 Shares of common stock issued pursuant to PBUs vested, net of forfeitures 502,593 Shares of restricted common stock surrendered upon vesting/exercise (1) 386,241 Shares of restricted common stock forfeited 1,360 (1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

Interest Expense (Tables)

Interest Expense (Tables)	3 Months Ended
	Mar. 31, 2016
Interest Expense [Abstract]
Schedule Of Components Of Interest Expense	The following table summarizes the components of interest expense for the periods indicated: For the Three Months Ended March 31, 2016 2015 (in thousands) Interest expense: Cash and accrued $ 8,907 $ 7,928 Amortization of deferred financing costs (1) 990 822 Capitalized interest (599 ) (1,189 ) Total interest expense $ 9,298 $ 7,561 (1) The three months ended March 31, 2016 and 2015 includes $677,000 and $613,000, respectively, of debt discount accretion related to the Notes.

Earnings per Share (Tables)

Earnings per Share (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	For the Three Months Ended March 31, 2016 2015 (in thousands, except per share and share data) Net loss attributable to common stockholders $ (73,475 ) $ (3,004 ) Weighted average common shares outstanding - basic 78,788,133 77,114,826 Incremental shares from unvested restricted shares — — Incremental shares from outstanding stock options — — Incremental shares from outstanding PBUs — — Weighted average common shares outstanding - diluted 78,788,133 77,114,826 Net loss per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (0.04 ) Diluted $ (0.93 ) $ (0.04 ) Common shares excluded from denominator as anti-dilutive: Unvested restricted shares 1,316,418 450,556 Stock options — — Unvested PBUs 1,484,907 373,325 Total 2,801,325 823,881

Statement of Cash Flows - Sup26

Statement of Cash Flows - Supplemental Information (Tables)	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Statement of Cash Flows Supplemental Information	The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated: For the Three Months Ended March 31, 2016 2015 (in thousands) Cash paid for interest, net of capitalized amounts $ 1,378 $ (282 ) Non-cash transactions: Capital expenditures included in (excluded from) accounts payable and accrued drilling costs $ 3,538 $ (10,366 ) Capital expenditures included in accounts receivable $ 310 $ — Asset retirement obligation included in oil and natural gas properties $ 11 $ 77 Application of advances to operators $ (229 ) $ 8,457 Other $ 37 $ 23

Description of Business (Narrat

Description of Business (Narrative) (Details) $ in Thousands	Apr. 08, 2016USD ($)	Feb. 19, 2016USD ($)	Mar. 31, 2016USD ($)well	Mar. 31, 2015USD ($)
Exploratory Wells Drilled [Line Items]
Proceeds from sale of oil and natural gas properties			$ 0	$ 2,008
Utica Shale and Point Pleasant
Exploratory Wells Drilled [Line Items]
Successful dry gas wells drilled | well			2
Appalachian Basin
Exploratory Wells Drilled [Line Items]
Proceeds from sale of oil and natural gas properties		$ 80,000
Appalachian Basin | Subsequent Event
Exploratory Wells Drilled [Line Items]
Proceeds from sale of oil and natural gas properties	$ 76,600

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	Apr. 08, 2016	Feb. 19, 2016	Mar. 31, 2016	Mar. 31, 2015
Accounting Policies [Line Items]
Proceeds from sale of oil and natural gas properties			$ 0	$ 2,008
Outstanding borrowing reduced due to repayment of credit facility			$ 20,370	$ 5,000
Appalachian Basin
Accounting Policies [Line Items]
Proceeds from sale of oil and natural gas properties		$ 80,000
Subsequent Event | Revolving Credit Facility
Accounting Policies [Line Items]
Outstanding borrowing reduced due to repayment of credit facility	$ 80,000
Subsequent Event | Appalachian Basin
Accounting Policies [Line Items]
Proceeds from sale of oil and natural gas properties	76,600
Revenue suspense liabilities	$ 2,800

Property, Plant and Equipment29

Property, Plant and Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Unproved properties, excluded from amortization:
Drilling in progress costs	$ 3,155	$ 1,533
Acreage acquisition costs	90,965	82,560
Capitalized interest	9,101	8,516
Total unproved properties excluded from amortization	$ 103,221	$ 92,609

Property, Plant and Equipment30

Property, Plant and Equipment (Narrative) (Details) Boe in Millions	Apr. 08, 2016USD ($)	Apr. 02, 2016$ / MMBTU$ / bbl	Feb. 19, 2016USD ($)	Dec. 16, 2015USD ($)awell	Sep. 30, 2010USD ($)	Mar. 31, 2016USD ($)well	Mar. 31, 2015USD ($)	Dec. 31, 2015Boe
Property, Plant and Equipment [Line Items]
Discount rate for estimated future cash flows						10.00%
Estimated proved reserves volume | Boe								55.9
Proceeds from sale of natural gas and oil properties						$ 0	$ 2,008,000
Percentage difference of fair value to purchase price				6.00%
Assets, fair value adjustment				$ 0
Gastar Exploration USA | Atinum Participation Agreement
Property, Plant and Equipment [Line Items]
Adjusted purchase price					$ 70,000,000
Working interest In wells (percentage)					50.00%
Percentage of lease bonuses and third party leasing costs up to 20 million to be received					10.00%
Percentage of lease bonuses and third party leasing costs above 20 million to be received					5.00%
Percentage of obligated share in future acquisitions					50.00%
Term of development program					3 years
Participation agreement expiry date					Nov. 1, 2015
Gastar Exploration USA | Atinum Participation Agreement | Maximum
Property, Plant and Equipment [Line Items]
Third party oil and gas leasing cost					$ 20,000,000
Gastar Exploration USA | Atinum Participation Agreement | Minimum | Before Price Decline
Property, Plant and Equipment [Line Items]
Productive gas wells, number of wells to be drilled | well						60
Gastar Exploration USA | Atinum Participation Agreement | Minimum | After Price Decline
Property, Plant and Equipment [Line Items]
Productive gas wells, number of wells to be drilled | well						51
Husky Acquisition
Property, Plant and Equipment [Line Items]
Gross wells | well				103
Net wells | well				10.2
Acquisition of oil and natural gas properties				$ 42,100,000
Escrow for pending resolution of title defects and purchase of overrides recorded in other assets				$ 4,900,000
Net acres | a				11,000
Fair market valuation amount				$ 44,600,000
Husky Acquisition | General and Administrative Expense
Property, Plant and Equipment [Line Items]
Transaction and integration costs				$ 1,300,000
Appalachian Basin
Property, Plant and Equipment [Line Items]
Proceeds from sale of natural gas and oil properties			$ 80,000,000
Marcellus Shale | Gastar Exploration USA | Atinum Participation Agreement
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells) | well						74
Utica Shale | Gastar Exploration USA | Atinum Participation Agreement
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells) | well						2
Subsequent Event | Appalachian Basin
Property, Plant and Equipment [Line Items]
Proceeds from sale of natural gas and oil properties	$ 76,600,000
Subsequent Event | Natural Gas
Property, Plant and Equipment [Line Items]
Decrease in average reserve price | $ / MMBTU		2.34
Subsequent Event | Crude Oil And N G L Per Barrel
Property, Plant and Equipment [Line Items]
Decrease in average reserve price | $ / bbl		45.16

Property, Plant and Equipment31

Property, Plant and Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) $ in Thousands		3 Months Ended
		Mar. 31, 2016USD ($)$ / MMBTU$ / bbl	Mar. 31, 2015USD ($)$ / MMBTU$ / bbl
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Impairment recorded (pre-tax) (in thousands) | $		$ 48,497	$ 0
Natural Gas Per Thousand Cubic Feet
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe | $ / MMBTU	[1]	2.40	3.88
Crude Oil And N G L Per Barrel
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe | $ / bbl	[1]	46.26	82.72
[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 spot natural gas prices and West Texas Intermediate spot oil prices.

Property, Plant And Equipment32

Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Husky Acquisition
Business Acquisition [Line Items]
Revenues		$ 36,831
Net Loss		$ (1,882)
Loss per share, Basic		$ (0.02)
Loss per share, Diluted		$ (0.02)
Appalachian Basin
Business Acquisition [Line Items]
Revenues	$ 11,621	$ 28,152
Net Loss	$ (68,647)	$ (6,969)
Loss per share, Basic	$ (0.87)	$ (0.09)
Loss per share, Diluted	$ (0.87)	$ (0.09)

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details)

Mar. 09, 2016USD ($)

Jun. 07, 2013

May. 15, 2013USD ($)

Mar. 31, 2016USD ($)

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Sep. 29, 2016

Jun. 30, 2016

Jun. 29, 2016

May. 02, 2016USD ($)

Apr. 10, 2016USD ($)

Apr. 08, 2016USD ($)

Mar. 30, 2016

Dec. 31, 2015USD ($)

Mar. 09, 2015USD ($)

Mar. 08, 2015USD ($)

Nov. 15, 2013

Line of Credit Facility [Line Items]

Waiver expiration date

Mar. 10, 2016

Aggregate principal amount

$ 325,000,000

$ 325,000,000

Second Amended and Restated Revolving Credit Facility

Line of Credit Facility [Line Items]

Interest rate description

borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent, (ii) the federal funds rate plus 50 basis points and (iii) LIBOR plus 1.0%.

Annual commitment fee (percentage)

0.50%

Revolving credit facility scheduled maturity date

Nov. 14, 2017

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

65.00%

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

250.00%

Revolving credit facility borrowing base

$ 180,000,000

$ 145,000,000

Borrowings outstanding

179,600,000

Letters of credit outstanding

$ 370,000

Scheduled borrowing base redetermination month and year

2016-05

Increase in current borrowing base

$ 50,000,000

Increase in adjusted consolidated net tangibles assets

17.50%

Second Amended and Restated Revolving Credit Facility | Subsequent Event

Line of Credit Facility [Line Items]

Borrowings outstanding

$ 99,600,000

Letters of credit issued

$ 370,000

Second Amended and Restated Revolving Credit Facility | Minimum

Line of Credit Facility [Line Items]

Line of credit facility covenant compliance Current Ratio

100.00%

Second Amended and Restated Revolving Credit Facility | Maximum

Line of Credit Facility [Line Items]

Line of credit facility covenant compliance indebtedness to EBITDA Ratio

400.00%

Second Amended and Restated Revolving Credit Facility | Federal Funds Rate

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

0.50%

Second Amended and Restated Revolving Credit Facility | LIBOR

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

1.00%

Second Amended and Restated Revolving Credit Facility | Prime Rate | Minimum

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

1.00%

Second Amended and Restated Revolving Credit Facility | Prime Rate | Maximum

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

2.00%

Second Amended and Restated Revolving Credit Facility | Eurodollar Rate | Minimum

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

2.00%

Second Amended and Restated Revolving Credit Facility | Eurodollar Rate | Maximum

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

3.00%

Amendment to Second Amended and Restated Revolving Credit Facility

Line of Credit Facility [Line Items]

Revolving credit facility borrowing base

$ 200,000,000

Interest coverage ratio

250.00%

200.00%

Amendment to Second Amended and Restated Revolving Credit Facility | Scenario Forecast

Line of Credit Facility [Line Items]

Leverage ratio

4

4.25

4.75

5

5.25

4

Senior Secured Notes Due 2018

Line of Credit Facility [Line Items]

Aggregate principal amount

$ 325,000,000

Debt instrument interest rate description

The Notes bear interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year.

Interest rate

8.625%

8.625%

Debt instrument maturity date

May 15, 2018

Percentage of aggregate principal amount

101.00%

Senior Secured Notes Due 2018 | Scenario Forecast

Line of Credit Facility [Line Items]

Leverage ratio

2

2.25

Amendment No. 8

Line of Credit Facility [Line Items]

Revolving credit facility borrowing base

$ 180,000,000

$ 200,000,000

Threshold for automatic reductions of the borrowing base in connection with asset sales

5,000,000

Threshold for lenders consent requirement in connection with asset sales

$ 5,000,000

Amendment No. 8 | Subsequent Event

Line of Credit Facility [Line Items]

Revolving credit facility borrowing base

$ 100,000,000

$ 100,000,000

Amendment No. 8 | Scenario Forecast

Line of Credit Facility [Line Items]

Leverage ratio

2

2.50

Interest coverage ratio

250.00%

110.00%

Amendment No. 8 | Maximum | Scenario Forecast

Line of Credit Facility [Line Items]

Leverage ratio

4

Amendment No. 8 | Eurodollar Rate

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

4.00%

Amendment No. 8 | Reference Rate

Line of Credit Facility [Line Items]

Applicable interest margin (percentage)

3.00%

Long-Term Debt - Summary of Not

Long-Term Debt - Summary of Notes Balance (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Notes, principal balance	$ 325,000,000	$ 325,000,000
Unamortized discounts	(6,474,000)	(7,151,000)
Deferred financing costs	(1,229,000)	(1,373,000)
Notes, net	$ 317,297,000	$ 316,476,000

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Assets:
Cash and cash equivalents	$ 26,950	$ 50,074
Assets, Commodity derivative contracts	16,076	24,869
Liabilities:
Liabilities, Commodity derivative contracts		(451)
Total	43,026	74,492
Level 1
Assets:
Cash and cash equivalents	26,950	50,074
Liabilities:
Total	26,950	50,074
Level 3
Assets:
Assets, Commodity derivative contracts	16,076	24,869
Liabilities:
Liabilities, Commodity derivative contracts		(451)
Total	$ 16,076	$ 24,418

Fair Value Measurements (Net Ch

Fair Value Measurements (Net Change in Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
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 March 31, 2016 and 2015		$ 6,500	$ 4,300
Fair Value, Measurements, Recurring
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		24,418	27,502
Total gains included in earnings		285	10,223
Purchases		0	866
Issuances		0	(186)
Settlements	[1]	(8,627)	(6,582)
Balance at end of period		16,076	31,823
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 March 31, 2016 and 2015		$ (6,497)	$ 4,252
[1]	Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) $ in Millions	Mar. 31, 2016USD ($)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of long-term debt	$ 388.4

Derivative Instruments and He38

Derivative Instruments and Hedging Activity (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Change in fair value of commodity derivative contracts	$ 6.5	$ 4.3

Derivative Instruments and He39

Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	3 Months Ended
	Mar. 31, 2016MMBTU$ / MMBTU$ / bblbbl
Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | MMBTU	5,000
Total of Notional Volume (MMBtus) | MMBTU	1,825,000
Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Short | Natural Gas
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.35
Producer Three-way Collar 1 - 2016 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | MMBTU	2,500	[1]
Total of Notional Volume (MMBtus) | MMBTU	230,000	[1]
Producer Three-way Collar 1 - 2016 | Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3	[1]
Producer Three-way Collar 1 - 2016 | Short | Natural Gas
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	3.65	[1]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.25	[1]
Producer Three-way Collar 2 - 2016 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | MMBTU	2,000	[2]
Total of Notional Volume (MMBtus) | MMBTU	306,000	[2]
Producer Three-way Collar 2 - 2016 | Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	4	[2]
Producer Three-way Collar 2 - 2016 | Short | Natural Gas
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4.58	[2]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.25	[2]
Producer Three-way Collar 3 - 2016 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | MMBTU	5,000	[2]
Total of Notional Volume (MMBtus) | MMBTU	765,000	[2]
Producer Three-way Collar 3 - 2016 | Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.40	[2]
Producer Three-way Collar 3 - 2016 | Short | Natural Gas
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4.10	[2]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.65	[2]
Producer Three-way Collar 1 - 2017 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | MMBTU	5,000
Total of Notional Volume (MMBtus) | MMBTU	1,825,000
Producer Three-way Collar 1 - 2017 | Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Producer Three-way Collar 1 - 2017 | Short | Natural Gas
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.35
Fixed Price Swap - Natural Gas Liquids 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	500	[2]
Total of Notional Volume (Bbls) | bbl	76,500	[2]
Base Fixed Price (Price per MMBtu or Bbl)	20.79	[2]
Crude Oil | Costless Three-way Collar 1 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	250	[2],[3]
Total of Notional Volume (Bbls) | bbl	38,250	[2]
Crude Oil | Costless Three-way Collar 1 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	85	[2]
Crude Oil | Costless Three-way Collar 1 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	65	[2]
Ceiling (Short) (Price per MMBtu or Bbl)	95.10	[2]
Crude Oil | Costless Three-way Collar 2 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	330	[2],[3]
Total of Notional Volume (Bbls) | bbl	50,490	[2]
Crude Oil | Costless Three-way Collar 2 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	80	[2]
Crude Oil | Costless Three-way Collar 2 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	65	[2]
Ceiling (Short) (Price per MMBtu or Bbl)	97.35	[2]
Crude Oil | Costless Three-way Collar 3 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	450	[2],[3]
Total of Notional Volume (Bbls) | bbl	68,850	[2]
Crude Oil | Costless Three-way Collar 3 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	57.50	[2]
Crude Oil | Costless Three-way Collar 3 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	42.50	[2]
Ceiling (Short) (Price per MMBtu or Bbl)	80	[2]
Crude Oil | Put Spread 1 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	550	[2],[3]
Total of Notional Volume (Bbls) | bbl	84,150	[2]
Crude Oil | Put Spread 1 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	85	[2]
Crude Oil | Put Spread 1 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	65	[2]
Crude Oil | Put Spread 2 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	300	[2],[3]
Total of Notional Volume (Bbls) | bbl	45,900	[2]
Crude Oil | Put Spread 2 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	85.50	[2]
Crude Oil | Put Spread 2 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	65.50	[2]
Crude Oil | Costless Three-way Collar 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	280	[3]
Total of Notional Volume (Bbls) | bbl	102,200
Crude Oil | Costless Three-way Collar 1 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	80
Crude Oil | Costless Three-way Collar 1 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	65
Ceiling (Short) (Price per MMBtu or Bbl)	97.25
Crude Oil | Costless Three-way Collar 2 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	250	[3]
Total of Notional Volume (Bbls) | bbl	91,250
Crude Oil | Costless Three-way Collar 2 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	80
Crude Oil | Costless Three-way Collar 2 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	60
Ceiling (Short) (Price per MMBtu or Bbl)	98.70
Crude Oil | Costless Three-way Collar 3 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	200	[3]
Total of Notional Volume (Bbls) | bbl	73,000
Crude Oil | Costless Three-way Collar 3 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	60
Crude Oil | Costless Three-way Collar 3 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	42.50
Ceiling (Short) (Price per MMBtu or Bbl)	85
Crude Oil | Put Spread 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	500	[3]
Total of Notional Volume (Bbls) | bbl	182,500
Crude Oil | Put Spread 1 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	82
Crude Oil | Put Spread 1 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	62
Crude Oil | Costless Three-way Collar 4 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	200	[3]
Total of Notional Volume (Bbls) | bbl	73,000
Crude Oil | Costless Three-way Collar 4 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	57.50
Crude Oil | Costless Three-way Collar 4 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	42.50
Ceiling (Short) (Price per MMBtu or Bbl)	76.13
Crude Oil | Put Spread 1 - 2018
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	425	[3],[4]
Total of Notional Volume (Bbls) | bbl	103,275	[4]
Crude Oil | Put Spread 1 - 2018 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	80	[4]
Crude Oil | Put Spread 1 - 2018 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl)	60	[4]
[1]	For the period August to October 2016.
[2]	For the period August to December 2016.
[3]	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
[4]	For the period January to August 2018.

Derivative Instruments and He40

Derivative Instruments and Hedging Activity (Summary of Information Regarding Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Current commodity derivative put premium payable		$ 1,723	$ 3,194
Long-term commodity derivative put premium payable		2,339	2,788
Total unamortized put premium liabilities	$ 4,062	$ 4,062	$ 5,982
Put Premium Liabilities [Roll Forward]
Put premium liabilities, beginning balance	5,982
Amortization of put premium liabilities	0
Settlement of put premium liabilities	(1,920)
Put premium liabilities, ending balance	$ 4,062

Derivative Instruments and He41

Derivative Instruments and Hedging Activity (Summary of Amortization of Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
August to December 2016	$ 1,275
January to December 2017	1,819
January to August 2018	968
Total unamortized put premium liabilities	$ 4,062	$ 5,982

Derivative Instruments and He42

Derivative Instruments and Hedging Activity (Summary of Information on the Location and Amounts of Derivative Fair Values and Derivative Gains and Losses) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Gain on commodity derivatives contracts	$ 285	$ 10,223
Commodity Contract
Derivatives, Fair Value [Line Items]
Gain on commodity derivatives contracts	285	10,223
Commodity Contract | Gain on commodity derivatives contracts
Derivatives, Fair Value [Line Items]
Gain on commodity derivatives contracts	285	$ 10,223
Commodity Contract | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Total derivatives not designated as hedging instruments	16,076		$ 24,418
Commodity Contract | Current assets | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	7,767		15,534
Commodity Contract | Other assets | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	8,309		9,335
Commodity Contract | Long-term liabilities | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	$ 0		$ (451)

Capital Stock (Narrative) (Deta

Capital Stock (Narrative) (Details)	Mar. 09, 2016	Jan. 18, 2016Right$ / shares	Apr. 24, 2014shares	Apr. 30, 2016USD ($)	Mar. 31, 2016USD ($)$ / sharesshares	Mar. 31, 2015USD ($)	Dec. 31, 2015$ / sharesshares	May. 07, 2015USD ($)
Class Of Stock [Line Items]
Aggregate offering price | $								$ 50,000,000
Issuance of shares - cash, net of offering costs (shares)					0
Number of rights issued on dividend declared | Right		1
Dividend rights description					The Rights generally become exercisable on the earlier of (i) ten business days after any person or group obtains beneficial ownership of 4.9% of the Company’s outstanding common stock (an “Acquiring Person”) or (ii) ten business days after commencement of a tender or exchange offer resulting in any person or group becoming an Acquiring Person.
Exercise price description					In the event that, after a person or a group has become an Acquiring Person, the Company is acquired in a merger or other business combination transaction (or 50% or more of the Company’s assets or earning power are sold), proper provision will be made so that each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then-current exercise price of the Right, that number of shares of common stock of the acquiring company having a market value at the time of that transaction equal to two times the exercise price.
Percent of ownership in outstanding common stock		4.90%
Rights redemption price per right | $ / shares		$ 0.001
Rights exchange description					At any time after any person or group becomes an Acquiring Person, the Company may generally exchange each Right in whole or in part at an exchange ratio of two shares of common stock per outstanding Right, subject to adjustment.
Expiration date of rights		Jan. 18, 2019
Preferred stock, shares authorized					40,000,000		40,000,000
Dividends on preferred stock | $					$ 3,618,000	$ 3,618,000
Preferred stock dividends payment conditions applied commencement period	2016-04
Common shares reserved for the exercise of stock options					741,600
2006 Long-Term Stock Incentive Plan
Class Of Stock [Line Items]
Shares reserved for issuance under LTIP			3,000,000
Shares available for future issuance (no more than) (shares)					996,980
Gastar Exploration USA
Class Of Stock [Line Items]
Preferred stock, shares authorized					40,000,000
Series C Preferred Stock
Class Of Stock [Line Items]
Dividend payment terms					The dividend was paid to stockholders of record on January 28, 2016. Each Right entitles the holder, subject to the terms of the Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $6.96, subject to certain adjustments.
Preferred stock, dividend rate, per share | $ / shares		$ 6.96
Dividends payable record date		Jan. 28, 2016
Series A Preferred Stock
Class Of Stock [Line Items]
Preferred stock, shares authorized					10,000,000		10,000,000
Preferred stock, dividend rate, percentage (percentage)					8.625%
Preferred stock, par value | $ / shares					$ 0.01		$ 0.01
Redemption price | $ / shares					$ 25		$ 25
Preferred stock, shares issued					4,045,000		4,045,000
Preferred stock, shares outstanding					4,045,000		4,045,000
Dividends on preferred stock | $					$ 2,200,000
Fixed rate preferred dividend increases percentage if suspension more than one year	2.00%
Series A Preferred Stock | Subsequent Event
Class Of Stock [Line Items]
Dividend declared or paid | $				$ 0
Series B Preferred Stock
Class Of Stock [Line Items]
Preferred stock, shares authorized					10,000,000		10,000,000
Preferred stock, dividend rate, percentage (percentage)					10.75%
Preferred stock, par value | $ / shares					$ 0.01		$ 0.01
Redemption price | $ / shares					$ 25		$ 25
Preferred stock, shares issued					2,140,000		2,140,000
Preferred stock, shares outstanding					2,140,000		2,140,000
Dividends on preferred stock | $					$ 1,400,000
Fixed rate preferred dividend increases percentage if suspension more than one year					2.00%
Preferred stock redemption price per share | $ / shares					$ 25
Period after change in control to redeem preferred stock					90 days
Option to convert shares of Series B Preferred Stock | $ / shares					$ 11.5207
Series B Preferred Stock | Subsequent Event
Class Of Stock [Line Items]
Dividend declared or paid | $				$ 0

Capital Stock (Schedule of Issu

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details)	3 Months Ended
	Mar. 31, 2016shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock issued pursuant to PBUs vested, net of forfeitures	502,593
Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of restricted common stock granted	1,698,064
Shares of restricted common stock vested	1,439,840
Shares of restricted common stock surrendered upon vesting/exercise	386,241	[1]
Shares of restricted common stock forfeited	1,360
[1]	Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

Interest Expense (Schedule of C

Interest Expense (Schedule of Components of Interest Expense) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Interest Expense [Abstract]
Cash and accrued		$ 8,907	$ 7,928
Amortization of deferred financing costs	[1]	990	822
Capitalized interest		(599)	(1,189)
Total interest expense		$ 9,298	$ 7,561
[1]	The three months ended March 31, 2016 and 2015 includes $677,000 and $613,000, respectively, of debt discount accretion related to the Notes.

Interest Expense (Schedule of46

Interest Expense (Schedule of Components of Interest Expense) (Parenthetical) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Interest Expense [Abstract]
Accretion of debt discount	$ 677,000	$ 613,000

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Current income tax benefit or provision	$ 0	$ 0

Earnings per Share (Schedule of

Earnings per Share (Schedule of Earnings per Share, Basic and Diluted, by Common Class, Including Two Class Method) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to common stockholders	$ (73,475)	$ (3,004)
Weighted average common shares outstanding basic (shares)	78,788,133	77,114,826
Incremental shares from unvested restricted shares	0	0
Incremental shares from outstanding stock options	0	0
Incremental shares from outstanding PBUs	0	0
Weighted average common shares outstanding diluted (shares)	78,788,133	77,114,826
Basic (dollars per share)	$ (0.93)	$ (0.04)
Diluted (dollars per share)	$ (0.93)	$ (0.04)
Common shares excluded from denominator as anti-dilutive (shares)	2,801,325	823,881
Unvested restricted shares
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Common shares excluded from denominator as anti-dilutive (shares)	1,316,418	450,556
Stock options
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Common shares excluded from denominator as anti-dilutive (shares)	0	0
Unvested PBUs
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Common shares excluded from denominator as anti-dilutive (shares)	1,484,907	373,325

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - USD ($)	Dec. 17, 2010	Dec. 29, 2015
Gastar Exploration Ltd vs US Specialty Ins Co and Axis Ins Co
Loss Contingencies [Line Items]
Settlement aggregate amount	$ 21,200,000
Directors and officers liability coverage limit	$ 20,000,000
Gastar Exploration Inc V Christopher Mc Arthur
Loss Contingencies [Line Items]
Damages sought in arbitration matter		$ 2,750,000

Statement of Cash Flows - Sup50

Statement of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of capitalized amounts	$ 1,378	$ (282)
Non-cash transactions:
Capital expenditures included in (excluded from) accounts payable and accrued drilling costs	3,538	(10,366)
Capital expenditures included in accounts receivable	310
Asset retirement obligation included in oil and natural gas properties	11	77
Application of advances to operators	(229)	8,457
Other	$ 37	$ 23