Gastar Exploration (GST) 10-Q 5 Nov 15 2015 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 02, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
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		80,147,147

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 10,351	$ 11,008
Accounts receivable, net of allowance for doubtful accounts of $0, respectively	9,860	30,841
Commodity derivative contracts	16,895	19,687
Prepaid expenses	611	2,083
Total current assets	37,717	63,619
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	91,126	128,274
Proved properties	1,233,716	1,124,367
Total oil and natural gas properties	1,324,842	1,252,641
Furniture and equipment	3,061	3,010
Total property, plant and equipment	1,327,903	1,255,651
Accumulated depreciation, depletion and amortization	(891,414)	(563,351)
Total property, plant and equipment, net	436,489	692,300
OTHER ASSETS:
Commodity derivative contracts	10,710	7,815
Deferred charges, net	2,625	2,586
Advances to operators and other assets	686	9,474
Total other assets	14,021	19,875
TOTAL ASSETS	488,227	775,794
CURRENT LIABILITIES:
Accounts payable	12,952	28,843
Revenue payable	5,350	9,122
Accrued interest	10,565	3,528
Accrued drilling and operating costs	6,672	5,977
Advances from non-operators	0	1,820
Commodity derivative premium payable	2,393	2,481
Asset retirement obligation	88	82
Other accrued liabilities	3,123	3,175
Total current liabilities	41,143	55,028
LONG-TERM LIABILITIES:
Long-term debt	397,189	360,303
Commodity derivative contracts	309	0
Commodity derivative premium payable	3,588	4,702
Asset retirement obligation	6,052	5,475
Total long-term liabilities	$ 407,138	$ 370,480
Commitments and contingencies (Note 11)
STOCKHOLDERS’ EQUITY:
Common stock	$ 78	$ 78
Additional paid-in capital	570,937	568,440
Accumulated deficit	(531,131)	(218,294)
Total stockholders’ equity	39,946	350,286
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	488,227	775,794
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	Sep. 30, 2015	Dec. 31, 2014
Accounts receivable, net of allowance for doubtful accounts	$ 0	$ 0
Preferred stock, shares authorized	40,000,000	40,000,000
Liquidation Preference	$ 25
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	275,000,000	275,000,000
Common stock, shares issued	80,147,147	78,632,810
Common stock, shares outstanding	80,147,147	78,632,810
Series A Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares issued	4,045,000	4,045,000
Preferred stock, shares outstanding	4,045,000	4,045,000
Liquidation Preference	$ 25	$ 25
Series B Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares issued	2,140,000	2,140,000
Preferred stock, shares outstanding	2,140,000	2,140,000
Liquidation Preference	$ 25	$ 25

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUES:
Oil and condensate	$ 12,835	$ 22,793	$ 45,772	$ 61,913
Natural gas	3,459	7,151	14,109	40,129
NGLs	791	5,139	5,071	16,689
Total oil, condensate, natural gas and NGLs revenues	17,085	35,083	64,952	118,731
Gain (loss) on commodity derivatives contracts	11,301	6,663	19,734	(8,761)
Total revenues	28,386	41,746	84,686	109,970
EXPENSES:
Production taxes	655	1,558	2,317	5,489
Lease operating expenses	5,214	4,136	18,475	13,057
Transportation, treating and gathering	615	397	1,654	3,168
Depreciation, depletion and amortization	15,394	11,111	45,945	33,773
Impairment of oil and natural gas properties	181,966	0	282,118	0
Accretion of asset retirement obligation	131	129	387	376
General and administrative expense	4,683	4,002	13,352	12,658
Total expenses	208,658	21,333	364,248	68,521
(LOSS) INCOME FROM OPERATIONS	(180,272)	20,413	(279,562)	41,449
OTHER INCOME (EXPENSE):
Interest expense	(7,933)	(6,991)	(22,430)	(20,794)
Investment income and other	4	4	10	15
Foreign transaction loss	0	(1)	0	(7)
(LOSS) INCOME BEFORE PROVISION FOR INCOME TAXES	(188,201)	13,425	(301,982)	20,663
Provision for income taxes	0	0	0	0
NET (LOSS) INCOME	(188,201)	13,425	(301,982)	20,663
Dividends on preferred stock	(3,618)	(3,618)	(10,855)	(10,805)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (191,819)	$ 9,807	$ (312,837)	$ 9,858
NET (LOSS) INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic (in dollars per share)	$ (2.47)	$ 0.16	$ (4.04)	$ 0.0017
Diluted (in dollars per share)	$ (2.47)	$ 0.15	$ (4.04)	$ 0.0016
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic (shares)	77,628,120	60,006,903	77,453,251	58,982,709
Diluted (shares)	77,628,120	63,399,446	77,453,251	62,306,480

Condensed Consolidated Stateme5

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income		$ (301,982)	$ 20,663
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		45,945	33,773
Impairment of oil and natural gas properties		282,118	0
Stock-based compensation		3,927	3,704
Total (gain) loss on commodity derivatives contracts		(19,734)	8,761
Cash settlements of matured commodity derivatives contracts, net		17,913	(7,705)
Cash premiums paid for commodity derivatives contracts		(45)	(185)
Amortization of deferred financing costs	[1]	2,652	2,270
Accretion of asset retirement obligation		387	376
Settlement of asset retirement obligation		(80)	(580)
Changes in operating assets and liabilities:
Accounts receivable		22,552	(4,242)
Prepaid expenses		1,472	(697)
Accounts payable and accrued liabilities		(289)	4,143
Net cash provided by operating activities		54,836	60,281
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties		(121,074)	(100,818)
Advances to operators		(2,325)	(43,337)
Acquisition of oil and natural gas properties - refund		0	4,209
Proceeds from sale of oil and natural gas properties		47,866	3,077
(Payments to) proceeds from non-operators		(1,820)	2,422
Purchase of furniture and equipment		(51)	(300)
Net cash used in investing activities		(77,404)	(134,747)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility		75,000	58,000
Repayment of revolving credit facility		(40,000)	(58,000)
Proceeds from issuance of common stock, net of issuance costs		0	101,513
Proceeds from issuance of preferred stock, net of issuance costs		0	2,064
Dividends on preferred stock		(10,855)	(10,805)
Deferred financing charges		(804)	(405)
Tax withholding related to restricted stock and performance based unit award vestings		(1,430)	(3,709)
Other		0	13
Net cash provided by financing activities		21,911	88,671
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(657)	14,205
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		11,008	32,393
CASH AND CASH EQUIVALENTS, END OF PERIOD		$ 10,351	$ 46,598
[1]	The three months ended September 30, 2015 and 2014 includes $644,000 and $584,000, respectively, of debt discount accretion related to the Notes. The nine months ended September 30, 2015 and 2014 includes $1.9 million and $1.7 million, respectively, of debt discount accretion related to the Notes.

Description of Business

Description of Business	9 Months Ended
	Sep. 30, 2015
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 is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and is testing other prospective formations on the same acreage, including the Meramec Shale and the Woodford Shale, which is commonly referred to as the STACK Play, and emerging prospective plays in the shallow Oswego formation and in the Osage formation, a deeper bench of the Mississippi Lime located below the Meramec. In West Virginia, Gastar has developed liquids-rich natural gas in the Marcellus Shale and has drilled and completed two successful dry gas Utica Shale/Point Pleasant wells on its acreage. Gastar has engaged a third-party to market certain Marcellus Shale and Utica/Point Pleasant acreage, primarily located in Marshall and Wetzel Counties, West Virginia, including producing wells. For any date or period prior to January 31, 2014, “Gastar,” the “Company,” “we,” “us,” “our” and similar terms refer collectively to Gastar Exploration, Inc. (formerly known as Gastar Exploration Ltd.) and its subsidiaries, including Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.), and for any date or period after January 31, 2014, such terms refer collectively to Gastar Exploration Inc. and its subsidiaries.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
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, 2014 (the “2014 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2014 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material item included in those notes has changed except as a result of normal transactions in the interim or as disclosed within this report. The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. The unaudited interim condensed consolidated financial statements of the Company include the consolidated accounts of all of its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications of prior year balances have been made to conform to the current year presentation; these reclassifications have no impact on net income (loss). The results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate. Recent Accounting Developments The following recently issued accounting pronouncements may impact the Company in future periods: Business Combinations. In September 2015, the FASB issued updated guidance as part of its simplification initiative that require that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, depletion and amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The update is effective for public business entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Company does not expect the adoption of this guidance to have a material impact on 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 be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018 and such proposal was subsequently adopted by the FASB in August 2015. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows and does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

Property, Plant and Equipment

Property, Plant and Equipment	9 Months Ended
	Sep. 30, 2015
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. The following table summarizes the components of unproved properties excluded from amortization at the dates indicated: September 30, 2015 December 31, 2014 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 15,302 $ 29,193 Acreage acquisition costs 65,190 91,362 Capitalized interest 10,634 7,719 Total unproved properties excluded from amortization $ 91,126 $ 128,274 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: 2015 Total Impairment September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 282,118 $ 181,966 $ 100,152 $ — 2014 Total Impairment September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 4.24 $ 4.10 $ 3.99 West Texas Intermediate oil price (per Bbl) (1) $ 99.08 $ 100.11 $ 98.30 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 expects to incur a further ceiling test impairment in the fourth quarter of 2015 assuming commodities prices do not increase dramatically. 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. Applying the actual October 1, 2015 average benchmark commodities prices of $44.74 per barrel for crude oil and $2.48 per Mcf for natural gas to November 1, 2015 and December 1, 2015, the Company forecasts that the benchmark 12-month average price applicable to year-end 2015 proved reserves under SEC rules would decrease to $50.37 per barrel for crude oil and $2.66 per Mcf for natural gas. If such pricing was used in applying the Company’s September 30, 2015 ceiling test for impairment, the Company estimates its impairment charge for the quarter ended September 30, 2015 would have increased by approximately $136.0 million. The Company’s estimated proved reserve volumes were 91.4 MMBoe at June 30, 2015 using the SEC-mandated historical twelve-month unweighted average pricing at such date. If such reserves estimates were made using the further reduced twelve-month average benchmark prices forecast for year-end 2015 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 June 30, 2015, excluding the impact of recent sales, would decrease by approximately 33.3 MMBoe primarily as a result of the loss of proved undeveloped locations and tail-end volumes which would not be economically producible at such lower prices. The foregoing estimates do not include any proved reserves expected to be acquired in the Company’s pending acquisition of interests in producing wells and acreage from the Company’s Mid-Continent AMI co-participant and certain other sellers, or proved reserves added through drilling activity since June 30, 2015. The Company’s proved reserves estimates as of December 31, 2015 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. Mid-Continent Acquisition On October 14, 2015, the Company entered into a definitive purchase and sale agreement to acquire additional working and net revenue interests in 103 gross (10.2 net) wells producing approximately 625 Boe/d and certain undeveloped acreage in the STACK and Hunton Limestone formations in its existing AMI from its AMI co-participant and other sellers for approximately $43.3 million 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 “Purchase Agreement”). The transaction is expected to close on or about November 30, 2015 with an effective date of July 1, 2015. In connection with the acquisition, the AMI participation agreements with the Company’s AMI co-participant will be dissolved. Mid-Continent Divestiture On July 6, 2015, the Company sold to an undisclosed private third party certain non-core assets comprised of 38 gross (16.7 net) wells producing approximately net 170 Boe/d (41% oil) for the three months ended March 31, 2015 and approximately 29,500 gross (19,200 net) acres in Kingfisher County, Oklahoma for approximately $45.9 million, reflecting an effective date of April 1, 2015 and customary closing adjustments. The sale is reflected as a reduction to the full cost pool and the Company did not record a gain or loss related to the divestiture as it was not significant to the full cost pool. Atinum Participation Agreement In September 2010, the Company entered into a participation agreement (the “Atinum Participation Agreement”) pursuant to which the Company ultimately assigned to an affiliate of Atinum Partners Co., Ltd. (“Atinum” and, together with the Company, the “Atinum co-participants), for total consideration of $70.0 million, a 50% working interest in certain undeveloped acreage and wells. Effective June 30, 2011, an AMI was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, the Company acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay the Company on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs up to $20.0 million and 5% of such costs on activities above $20.0 million. The Atinum 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 September 30, 2015, 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 and discussions are currently in progress regarding its replacement.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2015
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 (“Amendment No. 5”) to Second Amended and Restated Credit Agreement. Amendment No. 5 amended the Revolving Credit Facility to, among other things, (i) increase the borrowing base from $145.0 million to $200.0 million, (ii) adjust the 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. Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. The Company and its lender group may each request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. At September 30, 2015, the Revolving Credit Facility had a borrowing base of $200.0 million, with $80.0 million borrowings outstanding and availability of $120.0 million. The next regularly scheduled redetermination is set for May 2016. 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 September 30, 2015, the Company was in compliance with all financial covenants under the Revolving Credit Facility. Senior Secured Notes The Company has $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Notes”) outstanding under an indenture (the “Indenture”) by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year. The Notes mature on May 15, 2018. In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require the Company to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. The Notes will be guaranteed, jointly and severally, on a senior secured basis by certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of the Company's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of the Company's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to the Company's unsecured indebtedness and effectively subordinated to the Company's and Guarantors' under the Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation. The Indenture contains covenants that, among other things, limit the Company's ability and the ability of its subsidiaries to: · Transfer or sell assets or use asset sale proceeds; · Pay dividends or make distributions, redeem subordinated debt or make other restricted payments; · Make certain investments; incur or guarantee additional debt or issue preferred equity securities; · Create or incur certain liens on the Company's assets; · Incur dividend or other payment restrictions affecting future restricted subsidiaries; · Merge, consolidate or transfer all or substantially all of the Company's assets; · Enter into certain transactions with affiliates; and · Enter into certain sale and leaseback transactions. These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture. At September 30, 2015, the Notes reflected a balance of $317.2 million, net of unamortized discounts of $7.8 million, on the condensed consolidated balance sheets.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2015
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. There was no impairment of unproved properties for the three months ended September 30, 2015. For the nine months ended September 30, 2015, management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $60,000 of unproved properties to proved properties for the nine months ended September 30, 2015 related to acreage in Marcellus East. For the three and nine months ended September 30, 2014, management's evaluation of unproved properties resulted in an impairment of $2.7 million and $3.2 million, respectively, related to Marcellus East. As no other fair value measurements are required to be recognized on a non-recurring basis at September 30, 2015, no additional disclosures are provided at September 30, 2015. As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows: · Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds. · Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. · Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014: Fair value as of September 30, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 10,351 $ — $ — $ 10,351 Commodity derivative contracts — — 27,605 27,605 Liabilities: Commodity derivative contracts — — (309 ) (309 ) Total $ 10,351 $ — $ 27,296 $ 37,647 Fair value as of December 31, 2014 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 11,008 $ — $ — $ 11,008 Commodity derivative contracts — — 27,502 27,502 Liabilities: Commodity derivative contracts — — — — Total $ 11,008 $ — $ 27,502 $ 38,510 The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2015 and 2014. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at September 30, 2015 and 2014. Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Balance at beginning of period $ 22,373 $ (4,628 ) $ 27,502 $ 3,764 Total (losses) gains included in earnings 11,301 6,663 19,734 (8,761 ) Purchases 415 30 1,326 369 Issuances — — (1,313 ) — Settlements (1) (6,793 ) 813 (19,953 ) 7,506 Balance at end of period $ 27,296 $ 2,878 $ 27,296 $ 2,878 The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at September 30, 2015 and 2014 $ 4,511 $ 7,623 $ 986 $ (950 ) (1) Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations. At September 30, 2015, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at September 30, 2015 was $269.3 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	9 Months Ended
	Sep. 30, 2015
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 September 30, 2015 and 2014, the Company reported gains of $4.5 million and $7.6 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 September 30, 2015 and 2014. For the nine months ended September 30, 2015 and 2014, the Company reported a gain of $1.0 million and a loss of $1.0 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 September 30, 2015 and 2014. As of September 30, 2015, 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) 2015 Costless three-way collar 400 48,800 $ 85.00 $ 70.00 $ 96.50 2015 Costless three-way collar 312 38,100 $ 85.00 $ 65.00 $ 97.80 2015 Costless three-way collar 50 6,100 $ 85.00 $ 65.00 $ 96.25 2015 Costless collar 750 91,500 $ 52.50 $ — $ 62.05 2015 Costless collar 300 36,600 $ 52.50 $ — $ 68.10 2015 Costless collar 700 85,400 $ 45.00 $ — $ 55.25 2015 Fixed price swap 600 73,200 $ 72.54 $ — $ — 2015 Fixed price swap 250 30,500 $ 74.20 $ — $ — 2016 Costless three-way collar 275 100,600 $ 85.00 $ 65.00 $ 95.10 2016 Costless three-way collar 330 120,780 $ 80.00 $ 65.00 $ 97.35 2016 Costless three-way collar 450 164,700 $ 57.50 $ 42.50 $ 80.00 2016 Put spread 550 201,300 $ 85.00 $ 65.00 $ — 2016 Put spread 300 109,800 $ 85.50 $ 65.50 $ — 2017 Costless three-way collar 280 102,200 $ 80.00 $ 65.00 $ 97.25 2017 Costless three-way collar 242 88,150 $ 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 (2) 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 January to August 2018. As of September 30, 2015, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Call (Long) Ceiling (Short) (in MMBtus) 2015 Fixed price swap 400 48,800 $ 4.00 $ — $ — $ — $ — 2015 Fixed price swap 2,500 305,000 $ 4.06 $ — $ — $ — $ — 2015 Protective spread 2,600 317,200 $ 4.00 $ — $ 3.25 $ — $ — 2015 Fixed price swap 5,000 610,000 $ 3.49 $ — $ — $ — $ — 2015 Fixed price swap 2,000 244,000 $ 3.53 $ — $ — $ — $ — 2015 Producer three-way 2,500 305,000 $ — $ 3.70 $ 3.00 $ — $ 4.09 2015 Producer three-way 5,000 610,000 $ — $ 3.77 $ 3.00 $ — $ 4.11 2015 (1) Producer three-way 2,000 122,000 $ — $ 3.00 $ 2.25 $ — $ 3.34 2015 (1) Fixed price swap 10,000 610,000 $ 2.94 $ — $ — $ — $ — 2015 (2) Producer three-way 2,500 152,500 $ — $ 3.00 $ 2.25 $ — $ 3.65 2015 Basis swap (3) 2,500 305,000 $ (1.12 ) $ — $ — $ — $ — 2015 Basis swap (3) 2,500 305,000 $ (1.11 ) $ — $ — $ — $ — 2015 Basis swap (3) 2,500 305,000 $ (1.14 ) $ — $ — $ — $ — 2016 (4) Producer three-way 2,500 762,500 $ — $ 3.00 $ 2.25 $ — $ 3.65 2016 Protective spread 2,000 732,000 $ 4.11 $ — $ 3.25 $ — $ — 2016 Producer three-way 2,000 732,000 $ — $ 4.00 $ 3.25 $ — $ 4.58 2016 Producer three-way 5,000 1,830,000 $ — $ 3.40 $ 2.65 $ — $ 4.10 2016 Basis swap (5) 2,500 915,000 $ (1.10 ) $ — $ — $ — $ — 2016 Basis swap (5) 2,500 915,000 $ (1.02 ) $ — $ — $ — $ — 2016 Basis swap (5) 2,500 915,000 $ (1.00 ) $ — $ — $ — $ — 2016 (6) Producer three-way collar 7,500 682,500 $ — $ 3.00 $ 2.50 $ — $ 4.00 2016 (7) Producer three-way collar 5,000 1,375,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 2017 Short call 10,000 3,650,000 $ — $ — $ — $ — $ 4.75 2017 Basis swap (5) 2,500 912,500 $ (1.02 ) $ — $ — $ — $ — 2017 Basis swap (5) 2,500 912,500 $ (1.00 ) $ — $ — $ — $ — 2017 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 2018 Basis swap (5) 2,500 912,500 $ (1.02 ) $ — $ — $ — $ — 2018 Basis swap (5) 2,500 912,500 $ (1.00 ) $ — $ — $ — $ — 2018 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 (1) For the month of October 2015. (2) For the period November to December 2015. (3) Represents basis swaps at the sales point of Dominion South. (4) For the period January to October 2016. (5) Represents basis swaps at the sales point of TetcoM2. (6 ) For the period January to March 2016. (7 ) For the period April to December 2016. As of September 30, 2015, 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) 2015 Fixed price swap 250 30,500 $ 45.61 2015 Fixed price swap 500 61,000 $ 20.79 2016 Fixed price swap 500 183,000 $ 20.79 As of September 30, 2015, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features. In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period October 2015 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: September 30, 2015 December 31, 2014 (in thousands) Current commodity derivative put premium payable $ 2,393 $ 2,481 Long-term commodity derivative put premium payable 3,588 4,702 Total unamortized put premium liabilities $ 5,981 $ 7,183 For the Three Months Ended September 30, 2015 For the Nine Months Ended September 30, 2015 (in thousands) Put premium liabilities, beginning balance $ 5,566 $ 7,183 Amortization of put premium liabilities — (2,297 ) Additional put premium liabilities 415 1,095 Put premium liabilities, ending balance $ 5,981 $ 5,981 The following table provides information regarding the amortization of the deferred put premium liabilities by year as of September 30, 2015: Amortization (in thousands) January to December 2016 $ 3,194 January to December 2017 1,819 January to August 2018 968 Total unamortized put premium liabilities $ 5,981 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 September 30, 2015 December 31, 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 16,895 $ 19,687 Commodity derivative contracts Other assets 10,710 7,815 Commodity derivative contracts Long-term liabilities (309 ) — Total derivatives not designated as hedging instruments $ 27,296 $ 27,502 Amount of Gain (Loss) Recognized in Income on Derivatives For the Three Months Ended September 30, Location of Gain (Loss) Recognized in Income on Derivatives 2015 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Gain on commodity derivatives contracts $ 11,301 $ 6,663 Total $ 11,301 $ 6,663 Amount of Gain (Loss) Recognized in Income on Derivatives For the Nine Months Ended September 30, Location of (Gain) Loss Recognized in Income on Derivatives 2015 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Gain (loss) on commodity derivatives contracts $ 19,734 $ (8,761 ) Total $ 19,734 $ (8,761 )

Capital Stock

Capital Stock	9 Months Ended
	Sep. 30, 2015
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 FBR & Co. (formerly 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. During the three and nine months ended September 30, 2015, no shares were sold through the ATM program. Preferred Stock The Company currently has 40,000,000 shares of preferred stock authorized for issuance under its certificate of incorporation. The Company has designated 10,000,000 shares to constitute its 8.625% Series A Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 shares to constitute its 10.75% Series B Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share. Series A Preferred Stock At September 30, 2015, 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. There is no mandatory redemption of the Series A Preferred Stock. The Company pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference. For the three and nine months ended September 30, 2015, the Company recognized dividend expense of $2.2 million and $6.5 million, respectively, for the Series A Preferred Stock. Series B Preferred Stock At September 30, 2015, 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 pays cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference. For the three and nine months ended September 30, 2015, the Company recognized dividend expense of $1.4 million and $4.3 million, respectively, for the Series B Preferred Stock. Other Share Issuances The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the periods indicated: For the Three Months Ended September 30, 2015 For the Nine Months Ended September 30, 2015 Other share issuances: Shares of restricted common stock granted 5,380 1,426,604 Shares of restricted common stock vested 31,282 1,306,154 Shares of common stock issued pursuant to PBUs vested, net of forfeitures — 497,636 Shares of restricted common stock surrendered upon vesting/exercise (1) 3,167 385,405 Shares of restricted common stock forfeited — 24,498 (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 2,848,062 shares of common stock available for issuance under the LTIP at September 30, 2015. Shares Reserved At September 30, 2015, the Company had 866,600 common shares reserved for the exercise of stock options.

Interest Expense

Interest Expense	9 Months Ended
	Sep. 30, 2015
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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Interest expense: Cash and accrued $ 7,703 $ 7,297 $ 22,872 $ 21,639 Amortization of deferred financing costs (1) 916 779 2,652 2,270 Capitalized interest (686 ) (1,085 ) (3,094 ) (3,115 ) Total interest expense $ 7,933 $ 6,991 $ 22,430 $ 20,794 (1) The three months ended September 30, 2015 and 2014 includes $644,000 and $584,000, respectively, of debt discount accretion related to the Notes. The nine months ended September 30, 2015 and 2014 includes $1.9 million and $1.7 million, respectively, of debt discount accretion related to the Notes.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	9. Income Taxes For the three and nine months ended September 30, 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	9 Months Ended
	Sep. 30, 2015
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 September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands, except per share and share data) Net (loss) income attributable to common stockholders $ (191,819 ) $ 9,807 $ (312,837 ) $ 9,858 Weighted average common shares outstanding - basic 77,628,120 60,006,903 77,453,251 58,982,709 Incremental shares from unvested restricted shares — 2,614,215 — 2,587,345 Incremental shares from outstanding stock options — 115,421 — 109,755 Incremental shares from outstanding PBUs — 662,907 — 626,671 Weighted average common shares outstanding - diluted 77,628,120 63,399,446 77,453,251 62,306,480 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (2.47 ) $ 0.16 $ (4.04 ) $ 0.17 Diluted $ (2.47 ) $ 0.15 $ (4.04 ) $ 0.16 Common shares excluded from denominator as anti-dilutive: Unvested restricted shares 239,161 14,877 146,253 45,203 Stock options — — — — Unvested PBUs 503,271 — 84,179 — Total 742,432 14,877 230,432 45,203

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
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. On July 28, 2015, the parties submitted briefs in support of their respective positions regarding the issues left to be resolved in the case and the requisite amount of time for such proceedings. On August 11, 2015, the court entered a docket control order establishing the week of March 7, 2016 as the tentative week for the case to go to trial. The court has since canceled that trial date to allow additional time to brief discovery- and coverage-related issues. Husky Ventures, Inc. vs. J. Russell Porter, Michael A. Gerlich, Michael McCown, Keith R. Blair, Henry J. Hansen and John M. Selser Sr. (Case No. CIV-15-637-R) United States District Court for the Western District of Oklahoma. On June 9, 2015, Husky Ventures, Inc. (“Husky”) filed this action against five of the Company’s senior officers and our non-executive chairman of the board alleging that each of the defendants committed fraud by grossly understating the costs of certain oil and gas interests the Company acquired that were outside a Mid-Continent AMI between Husky and the Company while inflating the costs of interests simultaneously acquired within the AMI. Husky alleges this resulted in the defendants improperly shifting a disproportionate amount of acquisition costs away from the Company and to Husky. Husky sought to recover actual damages alleged to be in excess of $2.0 million, as well as punitive damages and attorneys’ fees. In connection with the Company’s entry into the Purchase Agreement (defined above), the Company, five of its senior officers, its non-executive chairman and Husky agreed to the settlement and mutual release of claims that the Company and Husky made against each other in this matter as well as any claims the parties may have had against each other in connection with the AMI participation agreements. In the event that the Purchase Agreement is terminated pursuant to its terms prior to the consummation of the transactions contemplated thereby, the settlement and release will be rescinded. 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	9 Months Ended
	Sep. 30, 2015
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 Nine Months Ended September 30, 2015 2014 (in thousands) Cash paid for interest, net of capitalized amounts $ 12,699 $ 11,668 Non-cash transactions: Capital expenditures (excluded from) included in accounts payable and accrued drilling costs $ (12,396 ) $ 1,601 Capital expenditures included in accounts receivable $ — $ 4,077 Asset retirement obligation included in oil and natural gas properties $ 276 $ 109 Application of advances to operators $ 11,113 $ 36,812 Expenses accrued for the issuance of common stock $ — $ 223 Other $ — $ (11 )

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Basis of Accounting	The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K.
Recent Accounting Developments	Recent Accounting Developments The following recently issued accounting pronouncements may impact the Company in future periods: Business Combinations. In September 2015, the FASB issued updated guidance as part of its simplification initiative that require that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, depletion and amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The update is effective for public business entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Company does not expect the adoption of this guidance to have a material impact on 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 be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018 and such proposal was subsequently adopted by the FASB in August 2015. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows and does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	9 Months Ended
	Sep. 30, 2015
Property Plant And Equipment [Abstract]
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	The following table summarizes the components of unproved properties excluded from amortization at the dates indicated: September 30, 2015 December 31, 2014 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 15,302 $ 29,193 Acreage acquisition costs 65,190 91,362 Capitalized interest 10,634 7,719 Total unproved properties excluded from amortization $ 91,126 $ 128,274
Schedule of Relevant Assumptions Used in Ceiling Test Computations	The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials: 2015 Total Impairment September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 282,118 $ 181,966 $ 100,152 $ — 2014 Total Impairment September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 4.24 $ 4.10 $ 3.99 West Texas Intermediate oil price (per Bbl) (1) $ 99.08 $ 100.11 $ 98.30 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.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring and Nonrecurring	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014: Fair value as of September 30, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 10,351 $ — $ — $ 10,351 Commodity derivative contracts — — 27,605 27,605 Liabilities: Commodity derivative contracts — — (309 ) (309 ) Total $ 10,351 $ — $ 27,296 $ 37,647 Fair value as of December 31, 2014 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 11,008 $ — $ — $ 11,008 Commodity derivative contracts — — 27,502 27,502 Liabilities: Commodity derivative contracts — — — — Total $ 11,008 $ — $ 27,502 $ 38,510
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2015 and 2014. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at September 30, 2015 and 2014. Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Balance at beginning of period $ 22,373 $ (4,628 ) $ 27,502 $ 3,764 Total (losses) gains included in earnings 11,301 6,663 19,734 (8,761 ) Purchases 415 30 1,326 369 Issuances — — (1,313 ) — Settlements (1) (6,793 ) 813 (19,953 ) 7,506 Balance at end of period $ 27,296 $ 2,878 $ 27,296 $ 2,878 The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at September 30, 2015 and 2014 $ 4,511 $ 7,623 $ 986 $ (950 ) (1) Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

Derivative Instruments and He21

Derivative Instruments and Hedging Activity (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative [Line Items]
Summary of Information Regarding Deferred Put Premium Liabilities	The following table provides information regarding the deferred put premium liabilities for the periods indicated: September 30, 2015 December 31, 2014 (in thousands) Current commodity derivative put premium payable $ 2,393 $ 2,481 Long-term commodity derivative put premium payable 3,588 4,702 Total unamortized put premium liabilities $ 5,981 $ 7,183 For the Three Months Ended September 30, 2015 For the Nine Months Ended September 30, 2015 (in thousands) Put premium liabilities, beginning balance $ 5,566 $ 7,183 Amortization of put premium liabilities — (2,297 ) Additional put premium liabilities 415 1,095 Put premium liabilities, ending balance $ 5,981 $ 5,981
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 September 30, 2015: Amortization (in thousands) January to December 2016 $ 3,194 January to December 2017 1,819 January to August 2018 968 Total unamortized put premium liabilities $ 5,981
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 September 30, 2015 December 31, 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 16,895 $ 19,687 Commodity derivative contracts Other assets 10,710 7,815 Commodity derivative contracts Long-term liabilities (309 ) — Total derivatives not designated as hedging instruments $ 27,296 $ 27,502 Amount of Gain (Loss) Recognized in Income on Derivatives For the Three Months Ended September 30, Location of Gain (Loss) Recognized in Income on Derivatives 2015 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Gain on commodity derivatives contracts $ 11,301 $ 6,663 Total $ 11,301 $ 6,663 Amount of Gain (Loss) Recognized in Income on Derivatives For the Nine Months Ended September 30, Location of (Gain) Loss Recognized in Income on Derivatives 2015 2014 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Gain (loss) on commodity derivatives contracts $ 19,734 $ (8,761 ) Total $ 19,734 $ (8,761 )
Natural Gas
Derivative [Line Items]
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of September 30, 2015, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Call (Long) Ceiling (Short) (in MMBtus) 2015 Fixed price swap 400 48,800 $ 4.00 $ — $ — $ — $ — 2015 Fixed price swap 2,500 305,000 $ 4.06 $ — $ — $ — $ — 2015 Protective spread 2,600 317,200 $ 4.00 $ — $ 3.25 $ — $ — 2015 Fixed price swap 5,000 610,000 $ 3.49 $ — $ — $ — $ — 2015 Fixed price swap 2,000 244,000 $ 3.53 $ — $ — $ — $ — 2015 Producer three-way 2,500 305,000 $ — $ 3.70 $ 3.00 $ — $ 4.09 2015 Producer three-way 5,000 610,000 $ — $ 3.77 $ 3.00 $ — $ 4.11 2015 (1) Producer three-way 2,000 122,000 $ — $ 3.00 $ 2.25 $ — $ 3.34 2015 (1) Fixed price swap 10,000 610,000 $ 2.94 $ — $ — $ — $ — 2015 (2) Producer three-way 2,500 152,500 $ — $ 3.00 $ 2.25 $ — $ 3.65 2015 Basis swap (3) 2,500 305,000 $ (1.12 ) $ — $ — $ — $ — 2015 Basis swap (3) 2,500 305,000 $ (1.11 ) $ — $ — $ — $ — 2015 Basis swap (3) 2,500 305,000 $ (1.14 ) $ — $ — $ — $ — 2016 (4) Producer three-way 2,500 762,500 $ — $ 3.00 $ 2.25 $ — $ 3.65 2016 Protective spread 2,000 732,000 $ 4.11 $ — $ 3.25 $ — $ — 2016 Producer three-way 2,000 732,000 $ — $ 4.00 $ 3.25 $ — $ 4.58 2016 Producer three-way 5,000 1,830,000 $ — $ 3.40 $ 2.65 $ — $ 4.10 2016 Basis swap (5) 2,500 915,000 $ (1.10 ) $ — $ — $ — $ — 2016 Basis swap (5) 2,500 915,000 $ (1.02 ) $ — $ — $ — $ — 2016 Basis swap (5) 2,500 915,000 $ (1.00 ) $ — $ — $ — $ — 2016 (6) Producer three-way collar 7,500 682,500 $ — $ 3.00 $ 2.50 $ — $ 4.00 2016 (7) Producer three-way collar 5,000 1,375,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 2017 Short call 10,000 3,650,000 $ — $ — $ — $ — $ 4.75 2017 Basis swap (5) 2,500 912,500 $ (1.02 ) $ — $ — $ — $ — 2017 Basis swap (5) 2,500 912,500 $ (1.00 ) $ — $ — $ — $ — 2017 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 2018 Basis swap (5) 2,500 912,500 $ (1.02 ) $ — $ — $ — $ — 2018 Basis swap (5) 2,500 912,500 $ (1.00 ) $ — $ — $ — $ — 2018 Producer three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ — $ 4.00 (1) For the month of October 2015. (2) For the period November to December 2015. (3) Represents basis swaps at the sales point of Dominion South. (4) For the period January to October 2016. (5) Represents basis swaps at the sales point of TetcoM2. (6 ) For the period January to March 2016. (7 ) For the period April to December 2016.
Natural Gas Liquids
Derivative [Line Items]
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of September 30, 2015, 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) 2015 Fixed price swap 250 30,500 $ 45.61 2015 Fixed price swap 500 61,000 $ 20.79 2016 Fixed price swap 500 183,000 $ 20.79
Crude Oil
Derivative [Line Items]
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of September 30, 2015, 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) 2015 Costless three-way collar 400 48,800 $ 85.00 $ 70.00 $ 96.50 2015 Costless three-way collar 312 38,100 $ 85.00 $ 65.00 $ 97.80 2015 Costless three-way collar 50 6,100 $ 85.00 $ 65.00 $ 96.25 2015 Costless collar 750 91,500 $ 52.50 $ — $ 62.05 2015 Costless collar 300 36,600 $ 52.50 $ — $ 68.10 2015 Costless collar 700 85,400 $ 45.00 $ — $ 55.25 2015 Fixed price swap 600 73,200 $ 72.54 $ — $ — 2015 Fixed price swap 250 30,500 $ 74.20 $ — $ — 2016 Costless three-way collar 275 100,600 $ 85.00 $ 65.00 $ 95.10 2016 Costless three-way collar 330 120,780 $ 80.00 $ 65.00 $ 97.35 2016 Costless three-way collar 450 164,700 $ 57.50 $ 42.50 $ 80.00 2016 Put spread 550 201,300 $ 85.00 $ 65.00 $ — 2016 Put spread 300 109,800 $ 85.50 $ 65.50 $ — 2017 Costless three-way collar 280 102,200 $ 80.00 $ 65.00 $ 97.25 2017 Costless three-way collar 242 88,150 $ 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 (2) 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 January to August 2018.

Capital Stock (Tables)

Capital Stock (Tables)	9 Months Ended
	Sep. 30, 2015
Stockholders Equity Note [Abstract]
Schedule of Issuances And Forfeitures Of Common Shares	The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the periods indicated: For the Three Months Ended September 30, 2015 For the Nine Months Ended September 30, 2015 Other share issuances: Shares of restricted common stock granted 5,380 1,426,604 Shares of restricted common stock vested 31,282 1,306,154 Shares of common stock issued pursuant to PBUs vested, net of forfeitures — 497,636 Shares of restricted common stock surrendered upon vesting/exercise (1) 3,167 385,405 Shares of restricted common stock forfeited — 24,498 (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)	9 Months Ended
	Sep. 30, 2015
Interest Expense [Abstract]
Schedule Of Components Of Interest Expense	The following table summarizes the components of interest expense for the periods indicated: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Interest expense: Cash and accrued $ 7,703 $ 7,297 $ 22,872 $ 21,639 Amortization of deferred financing costs (1) 916 779 2,652 2,270 Capitalized interest (686 ) (1,085 ) (3,094 ) (3,115 ) Total interest expense $ 7,933 $ 6,991 $ 22,430 $ 20,794 (1) The three months ended September 30, 2015 and 2014 includes $644,000 and $584,000, respectively, of debt discount accretion related to the Notes. The nine months ended September 30, 2015 and 2014 includes $1.9 million and $1.7 million, respectively, of debt discount accretion related to the Notes.

Earnings per Share (Tables)

Earnings per Share (Tables)	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	For the Three Months Ended September 30, For the Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands, except per share and share data) Net (loss) income attributable to common stockholders $ (191,819 ) $ 9,807 $ (312,837 ) $ 9,858 Weighted average common shares outstanding - basic 77,628,120 60,006,903 77,453,251 58,982,709 Incremental shares from unvested restricted shares — 2,614,215 — 2,587,345 Incremental shares from outstanding stock options — 115,421 — 109,755 Incremental shares from outstanding PBUs — 662,907 — 626,671 Weighted average common shares outstanding - diluted 77,628,120 63,399,446 77,453,251 62,306,480 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (2.47 ) $ 0.16 $ (4.04 ) $ 0.17 Diluted $ (2.47 ) $ 0.15 $ (4.04 ) $ 0.16 Common shares excluded from denominator as anti-dilutive: Unvested restricted shares 239,161 14,877 146,253 45,203 Stock options — — — — Unvested PBUs 503,271 — 84,179 — Total 742,432 14,877 230,432 45,203

Statement of Cash Flows - Sup25

Statement of Cash Flows - Supplemental Information (Tables)	9 Months Ended
	Sep. 30, 2015
Supplemental Cash Flow Information [Abstract]
Statement of Cash Flows Supplemental Information	The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated: For the Nine Months Ended September 30, 2015 2014 (in thousands) Cash paid for interest, net of capitalized amounts $ 12,699 $ 11,668 Non-cash transactions: Capital expenditures (excluded from) included in accounts payable and accrued drilling costs $ (12,396 ) $ 1,601 Capital expenditures included in accounts receivable $ — $ 4,077 Asset retirement obligation included in oil and natural gas properties $ 276 $ 109 Application of advances to operators $ 11,113 $ 36,812 Expenses accrued for the issuance of common stock $ — $ 223 Other $ — $ (11 )

Description of Business (Narrat

Description of Business (Narrative) (Details)	9 Months Ended
	Sep. 30, 2015well
Utica Shale and Point Pleasant
Exploratory Wells Drilled [Line Items]
Successful dry gas wells drilled	2

Property, Plant and Equipment27

Property, Plant and Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Unproved properties, excluded from amortization:
Drilling in progress costs	$ 15,302	$ 29,193
Acreage acquisition costs	65,190	91,362
Capitalized interest	10,634	7,719
Total unproved properties excluded from amortization	$ 91,126	$ 128,274

Property, Plant and Equipment28

Property, Plant and Equipment (Narrative) (Details)	Nov. 01, 2015$ / bbl$ / Mcf	Oct. 14, 2015USD ($)awellBoe	Jun. 30, 2015Boe	Sep. 30, 2010USD ($)	Mar. 31, 2015Boe	Sep. 30, 2015USD ($)well$ / bbl$ / Mcf	Jul. 06, 2015USD ($)awell
Property, Plant and Equipment [Line Items]
Discount rate for estimated future cash flows						10.00%
Increase in impairment charge | $						$ 136,000,000
Estimated proved reserves volume | Boe			91,400,000
Decrease in estimated proved reserves | Boe			33,300,000
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						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						51
Mid Continent Divestiture
Property, Plant and Equipment [Line Items]
Gross wells							38
Net wells							16.7
Production of wells (Boe/d) | Boe					170
Net acres (acres) | a							19,200
Percentage oil					41.00%
Gross acres (acres) | a							29,500
Total consideration | $							$ 45,900,000
Marcellus Shale | Gastar Exploration USA | Atinum Participation Agreement
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells)						74
Utica Shale | Gastar Exploration USA | Atinum Participation Agreement
Property, Plant and Equipment [Line Items]
Productive conventional wells (wells)						2
Natural Gas
Property, Plant and Equipment [Line Items]
Decrease in average reserve price | $ / Mcf						2.66
Crude Oil
Property, Plant and Equipment [Line Items]
Decrease in average reserve price | $ / bbl						50.37
Subsequent Event | Mid Continent
Property, Plant and Equipment [Line Items]
Gross wells		103
Net wells		10.2
Production of wells (Boe/d) | Boe		625
Net acres (acres) | a		11,000
Acquisition of oil and natural gas properties | $		$ 43,300,000
Subsequent Event | Natural Gas
Property, Plant and Equipment [Line Items]
Average commodity prices | $ / Mcf	2.48
Subsequent Event | Crude Oil
Property, Plant and Equipment [Line Items]
Average commodity prices | $ / bbl	44.74

Property, Plant and Equipment29

Property, Plant and Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) $ in Thousands		3 Months Ended						9 Months Ended
		Sep. 30, 2015USD ($)$ / MMBTU$ / bbl	Jun. 30, 2015USD ($)$ / MMBTU$ / bbl	Mar. 31, 2015USD ($)$ / MMBTU$ / bbl	Sep. 30, 2014USD ($)$ / MMBTU$ / bbl	Jun. 30, 2014USD ($)$ / MMBTU$ / bbl	Mar. 31, 2014USD ($)$ / MMBTU$ / bbl	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Impairment recorded (pre-tax) (in thousands) | $		$ 181,966	$ 100,152	$ 0	$ 0	$ 0	$ 0	$ 282,118	$ 0
Henry Hub natural gas price (per MMBtu)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe	[1]	3.06	3.39	3.88	4.24	4.10	3.99
West Texas Intermediate oil price (per Bbl)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe | $ / bbl	[1]	59.21	71.68	82.72	99.08	100.11	98.30
[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.

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details)

Jun. 07, 2013

May. 15, 2013USD ($)

Sep. 30, 2015USD ($)

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Sep. 29, 2016

Jun. 30, 2016

Jun. 29, 2016

Mar. 31, 2016

Mar. 30, 2016

Mar. 09, 2015USD ($)

Mar. 08, 2015USD ($)

Nov. 15, 2013

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

$ 200,000,000

$ 145,000,000

Borrowings outstanding

80,000,000

Borrowing availability

$ 120,000,000

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 | 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

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

Interest coverage ratio

250.00%

200.00%

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%

Long-term debt

$ 317,200,000

Unamortized discounts

$ 7,800,000

Senior Secured Notes Due 2018 | Scenario, Forecast

Line of Credit Facility [Line Items]

Leverage ratio

2

2.25

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount reclassified from unproved to proved properties			$ 60
Impairment of unproved properties	$ 0	$ 2,700		$ 3,200
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of long-term debt	$ 269,300		$ 269,300

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Assets:
Cash and cash equivalents	$ 10,351	$ 11,008
Assets, Commodity derivative contracts	27,605	27,502
Liabilities:
Liabilities, Commodity derivative contracts	(309)	0
Total	37,647	38,510
Level 1
Assets:
Cash and cash equivalents	10,351	11,008
Assets, Commodity derivative contracts	0	0
Liabilities:
Liabilities, Commodity derivative contracts	0	0
Total	10,351	11,008
Level 2
Assets:
Cash and cash equivalents	0	0
Assets, Commodity derivative contracts	0	0
Liabilities:
Liabilities, Commodity derivative contracts	0	0
Total	0	0
Level 3
Assets:
Cash and cash equivalents	0	0
Assets, Commodity derivative contracts	27,605	27,502
Liabilities:
Liabilities, Commodity derivative contracts	(309)	0
Total	$ 27,296	$ 27,502

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		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at September 30, 2015 and 2014		$ 4,500	$ 7,600	$ 1,000	$ (1,000)
Fair Value, Measurements, Recurring
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		22,373	(4,628)	27,502	3,764
Total (losses) gains included in earnings		11,301	6,663	19,734	(8,761)
Purchases		415	30	1,326	369
Issuances		0	0	(1,313)	0
Settlements	[1]	(6,793)	813	(19,953)	7,506
Balance at end of period		27,296	2,878	27,296	2,878
The amount of total gains (losses) for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at September 30, 2015 and 2014		$ 4,511	$ 7,623	$ 986	$ (950)
[1]	Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

Derivative Instruments and He34

Derivative Instruments and Hedging Activity (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Change in fair value of commodity derivative contracts	$ 4.5	$ 7.6	$ 1	$ (1)

Derivative Instruments and He35

Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	9 Months Ended
	Sep. 30, 2015MMBTU$ / MMBTU$ / bblbbl
Fixed Price Swap - Natural Gas Liquids 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	250
Total of Notional Volume (Bbls) | bbl	30,500
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl	45.61
Fixed Price Swap 2 - Natural Gas Liquids 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	500
Total of Notional Volume (Bbls) | bbl	61,000
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl	20.79
Fixed Price Swap - Natural Gas Liquids 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	500
Total of Notional Volume (Bbls) | bbl	183,000
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl	20.79
Crude Oil | Costless Three-way Collar 1 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	400	[1]
Total of Notional Volume (Bbls) | bbl	48,800
Crude Oil | Costless Three-way Collar 1 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	85
Crude Oil | Costless Three-way Collar 1 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	70
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	96.50
Crude Oil | Costless Three-way Collar 2 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	312	[1]
Total of Notional Volume (Bbls) | bbl	38,100
Crude Oil | Costless Three-way Collar 2 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	85
Crude Oil | Costless Three-way Collar 2 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	65
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	97.80
Crude Oil | Costless Three-way Collar 3 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	50	[1]
Total of Notional Volume (Bbls) | bbl	6,100
Crude Oil | Costless Three-way Collar 3 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	85
Crude Oil | Costless Three-way Collar 3 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	65
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	96.25
Crude Oil | Costless Collar 1 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	750	[1]
Total of Notional Volume (Bbls) | bbl	91,500
Crude Oil | Costless Collar 1 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	52.50
Crude Oil | Costless Collar 1 - 2015 | Short
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	62.05
Crude Oil | Costless Collar 2 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	300	[1]
Total of Notional Volume (Bbls) | bbl	36,600
Crude Oil | Costless Collar 2 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	52.50
Crude Oil | Costless Collar 2 - 2015 | Short
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	68.10
Crude Oil | Costless Collar 3 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	700	[1]
Total of Notional Volume (Bbls) | bbl	85,400
Crude Oil | Costless Collar 3 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	45
Crude Oil | Costless Collar 3 - 2015 | Short
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	55.25
Crude Oil | Fixed Price Swap 1 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	600	[1]
Total of Notional Volume (Bbls) | bbl	73,200
Crude Oil | Fixed Price Swap 1 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	72.54
Crude Oil | Fixed Price Swap 2 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	250	[1]
Total of Notional Volume (Bbls) | bbl	30,500
Crude Oil | Fixed Price Swap 2 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	74.20
Crude Oil | Costless Three-way Collar 1 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	275	[1]
Total of Notional Volume (Bbls) | bbl	100,600
Crude Oil | Costless Three-way Collar 1 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	85
Crude Oil | Costless Three-way Collar 1 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	65
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	95.10
Crude Oil | Costless Three-way Collar 2 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	330	[1]
Total of Notional Volume (Bbls) | bbl	120,780
Crude Oil | Costless Three-way Collar 2 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	80
Crude Oil | Costless Three-way Collar 2 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	65
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	97.35
Crude Oil | Costless Three-way Collar 3 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	450	[1]
Total of Notional Volume (Bbls) | bbl	164,700
Crude Oil | Costless Three-way Collar 3 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	57.50
Crude Oil | Costless Three-way Collar 3 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	42.50
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	80
Crude Oil | Put Spread 1 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	550	[1]
Total of Notional Volume (Bbls) | bbl	201,300
Crude Oil | Put Spread 1 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	85
Crude Oil | Put Spread 1 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	65
Crude Oil | Put Spread 2 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	300	[1]
Total of Notional Volume (Bbls) | bbl	109,800
Crude Oil | Put Spread 2 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	85.50
Crude Oil | Put Spread 2 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	65.50
Crude Oil | Costless Three-way Collar 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	280	[1]
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) | $ / bbl	80
Crude Oil | Costless Three-way Collar 1 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	65
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	97.25
Crude Oil | Costless Three-way Collar 2 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	242	[1]
Total of Notional Volume (Bbls) | bbl	88,150
Crude Oil | Costless Three-way Collar 2 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	80
Crude Oil | Costless Three-way Collar 2 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	60
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	98.70
Crude Oil | Costless Three-way Collar 3 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	200	[1]
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) | $ / bbl	60
Crude Oil | Costless Three-way Collar 3 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	42.50
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	85
Crude Oil | Put Spread 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	500	[1]
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) | $ / bbl	82
Crude Oil | Put Spread 1 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	62
Crude Oil | Costless Three-way Collar 4 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	200	[1]
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) | $ / 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) | $ / bbl	42.50
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl	76.13
Crude Oil | Put Spread 1 - 2018
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls) | bbl	425	[1],[2]
Total of Notional Volume (Bbls) | bbl	103,275	[2]
Crude Oil | Put Spread 1 - 2018 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl	80	[2]
Crude Oil | Put Spread 1 - 2018 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / bbl	60	[2]
Natural Gas | Fixed Price Swap 1 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	400
Total of Notional Volume (MMBtus)	48,800
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	4
Natural Gas | Fixed Price Swap 2 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtus)	305,000
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	4.06
Natural Gas | Protective Spread 1 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,600
Total of Notional Volume (MMBtus)	317,200
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	4
Natural Gas | Protective Spread 1 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.25
Natural Gas | Fixed Price Swap 3 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtus)	610,000
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	3.49
Natural Gas | Fixed Price Swap 4 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtus)	244,000
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	3.53
Natural Gas | Producer Three-way Collar 1 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500
Total of Notional Volume (MMBtus)	305,000
Natural Gas | Producer Three-way Collar 1 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.70
Natural Gas | Producer Three-way Collar 1 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4.09
Natural Gas | Producer Three-way Collar 2 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtus)	610,000
Natural Gas | Producer Three-way Collar 2 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.77
Natural Gas | Producer Three-way Collar 2 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4.11
Natural Gas | Producer Three-way Collar 3 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000	[3]
Total of Notional Volume (MMBtus)	122,000	[3]
Natural Gas | Producer Three-way Collar 3 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3	[3]
Natural Gas | Producer Three-way Collar 3 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.25	[3]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	3.34	[3]
Natural Gas | Fixed Price Swap 5 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000	[3]
Total of Notional Volume (MMBtus)	610,000	[3]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	2.94	[3]
Natural Gas | Producer Three-way Collar 4 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[4]
Total of Notional Volume (MMBtus)	152,500	[4]
Natural Gas | Producer Three-way Collar 4 - 2015 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3	[4]
Natural Gas | Producer Three-way Collar 4 - 2015 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.25	[4]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	3.65	[4]
Natural Gas | Basis Swap 1 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[5]
Total of Notional Volume (MMBtus)	305,000	[5]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1.12)	[5]
Natural Gas | Basis Swap 2 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[5]
Total of Notional Volume (MMBtus)	305,000	[5]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1.11)	[5]
Natural Gas | Basis Swap 3 - 2015
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[5]
Total of Notional Volume (MMBtus)	305,000	[5]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1.14)	[5]
Natural Gas | Producer Three-way Collar 1 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[6]
Total of Notional Volume (MMBtus)	762,500	[6]
Natural Gas | Producer Three-way Collar 1 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3	[6]
Natural Gas | Producer Three-way Collar 1 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.25	[6]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	3.65	[6]
Natural Gas | Protective Spread 2 - Natural Gas 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtus)	732,000
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	4.11
Natural Gas | Protective Spread 2 - Natural Gas 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.25
Natural Gas | Producer Three-way Collar 2 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,000
Total of Notional Volume (MMBtus)	732,000
Natural Gas | Producer Three-way Collar 2 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	4
Natural Gas | Producer Three-way Collar 2 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.25
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4.58
Natural Gas | Producer Three-way Collar 3 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtus)	1,830,000
Natural Gas | Producer Three-way Collar 3 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.40
Natural Gas | Producer Three-way Collar 3 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.65
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4.10
Natural Gas | Basis Swap 1 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtus)	915,000	[7]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1.10)	[7]
Natural Gas | Basis Swap 2 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtus)	915,000	[7]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1.02)	[7]
Natural Gas | Basis Swap 3 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtus)	915,000	[7]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1)	[7]
Natural Gas | Producer Three-way Collar 4 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	7,500	[8]
Total of Notional Volume (MMBtus)	682,500	[8]
Natural Gas | Producer Three-way Collar 4 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3	[8]
Natural Gas | Producer Three-way Collar 4 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.50	[8]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4	[8]
Natural Gas | Producer Three-way Collar 5 - 2016
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000	[9]
Total of Notional Volume (MMBtus)	1,375,000	[9]
Natural Gas | Producer Three-way Collar 5 - 2016 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3	[9]
Natural Gas | Producer Three-way Collar 5 - 2016 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.35	[9]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4	[9]
Natural Gas | Short Call - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	10,000
Total of Notional Volume (MMBtus)	3,650,000
Natural Gas | Short Call - 2017 | Short
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4.75
Natural Gas | Basis Swap 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtus)	912,500	[7]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1.02)	[7]
Natural Gas | Basis Swap 2 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtus)	912,500	[7]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1)	[7]
Natural Gas | Producer Three-way Collar 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtus)	1,825,000
Natural Gas | Producer Three-way Collar 1 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Natural Gas | Producer Three-way Collar 1 - 2017 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.35
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4
Natural Gas | Basis Swap 1 - 2018
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtus)	912,500	[7]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1.02)	[7]
Natural Gas | Basis Swap 2 - 2018
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	2,500	[7]
Total of Notional Volume (MMBtus)	912,500	[7]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	(1)	[7]
Natural Gas | Producer Three-way Collar 1 - 2018
Derivative [Line Items]
Average Daily Volume (MMBtus or Bbls)	5,000
Total of Notional Volume (MMBtus)	1,825,000
Natural Gas | Producer Three-way Collar 1 - 2018 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Natural Gas | Producer Three-way Collar 1 - 2018 | Short
Derivative [Line Items]
Put (Short) or Call (Long) (Price per MMBtu or Bbl) | $ / MMBTU	2.35
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4
[1]	Crude volumes hedged include oil, condensate and certain components of our NGLs production.
[2]	For the period January to August 2018.
[3]	For the month of October 2015.
[4]	For the period November to December 2015.
[5]	Represents basis swaps at the sales point of Dominion South.
[6]	For the period January to October 2016.
[7]	Represents basis swaps at the sales point of TetcoM2.
[8]	For the period January to March 2016.
[9]	For the period April to December 2016.

Derivative Instruments and He36

Derivative Instruments and Hedging (Summary of Information Regarding Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Current commodity derivative put premium payable	$ 2,393		$ 2,481
Long-term commodity derivative put premium payable	3,588		4,702
Total unamortized put premium liabilities	$ 5,981	$ 5,566	$ 7,183

Derivative Instruments and He37

Derivative Instruments and Hedging Activity (Summary of Information Regarding Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Put Premium Liabilities [Roll Forward]
Put premium liabilities, beginning balance	$ 5,566	$ 7,183
Amortization of put premium liabilities	0	(2,297)
Additional put premium liabilities	415	1,095
Put premium liabilities, ending balance	$ 5,981	$ 5,981

Derivative Instruments and He38

Derivative Instruments and Hedging Activity (Summary of Amortization of Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
January to December 2016	$ 3,194
January to December 2017	1,819
January to August 2018	968
Total unamortized put premium liabilities	$ 5,981	$ 5,566	$ 7,183

Derivative Instruments and He39

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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Gain (loss) on commodity derivatives contracts	$ 11,301	$ 6,663	$ 19,734	$ (8,761)
Commodity Contract
Derivatives, Fair Value [Line Items]
Gain (loss) on commodity derivatives contracts	11,301	6,663	19,734	(8,761)
Commodity Contract | Gain (loss) on commodity derivatives contracts
Derivatives, Fair Value [Line Items]
Gain (loss) on commodity derivatives contracts	11,301	$ 6,663	19,734	$ (8,761)
Commodity Contract | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Total derivatives not designated as hedging instruments	27,296		27,296		$ 27,502
Commodity Contract | Current assets | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	16,895		16,895		19,687
Commodity Contract | Other assets | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	10,710		10,710		7,815
Commodity Contract | Long-term liabilities | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	$ (309)		$ (309)		$ 0

Capital Stock (Narrative) (Deta

Capital Stock (Narrative) (Details) - USD ($)	Apr. 24, 2014	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	May. 07, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)		40,000,000		40,000,000			40,000,000
Liquidation Preference (per share)		$ 25		$ 25
Dividends on preferred stock		$ 3,618,000	$ 3,618,000	$ 10,855,000	$ 10,805,000
Common shares reserved for the exercise of stock options		866,600		866,600
Parent's 2006 Long-Term Stock Incentive Plan
Class of Stock [Line Items]
Increase in the number of share reserved for issuance	3,000,000
Common stock available for issuance		2,848,062		2,848,062
Series A Preferred Stock
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)		10,000,000		10,000,000			10,000,000
Preferred stock, dividend rate, percentage (percentage)				8.625%
Preferred stock par value per share		$ 0.01		$ 0.01			$ 0.01
Liquidation Preference (per share)		$ 25		$ 25			$ 25
Preferred stock, shares issued		4,045,000		4,045,000			4,045,000
Preferred stock, shares outstanding		4,045,000		4,045,000			4,045,000
Dividends on preferred stock		$ 2,200,000		$ 6,500,000
Series B Preferred Stock
Class of Stock [Line Items]
Preferred shares authorized for issuance (shares)		10,000,000		10,000,000			10,000,000
Preferred stock, dividend rate, percentage (percentage)				10.75%
Preferred stock par value per share		$ 0.01		$ 0.01			$ 0.01
Liquidation Preference (per share)		$ 25		$ 25			$ 25
Preferred stock, shares issued		2,140,000		2,140,000			2,140,000
Preferred stock, shares outstanding		2,140,000		2,140,000			2,140,000
Dividends on preferred stock		$ 1,400,000		$ 4,300,000
Preferred stock redemption price per share		$ 25		$ 25
Period after change in control to redeem preferred stock				90 days
Option to convert shares of Series B Preferred Stock		$ 11.5207		$ 11.5207
At the Market Sales Agreement to Sell Shares of Common Stock | MLV and Company LLC
Class of Stock [Line Items]
Number of shares sold through ATM program		0		0
At the Market Sales Agreement to Sell Shares of Common Stock | MLV and Company LLC | Maximum
Class of Stock [Line Items]
Aggregate offering price						$ 50,000,000

Capital Stock (Schedule of Issu

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details) - shares		3 Months Ended	9 Months Ended
		Sep. 30, 2015	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock issued pursuant to PBUs vested, net of forfeitures		0	497,636
Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of restricted common stock granted		5,380	1,426,604
Shares of restricted common stock vested		31,282	1,306,154
Shares of restricted common stock surrendered upon vesting/exercise	[1]	3,167	385,405
Shares of restricted common stock forfeited		0	24,498
[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		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Interest Expense [Abstract]
Cash and accrued		$ 7,703	$ 7,297	$ 22,872	$ 21,639
Amortization of deferred financing costs	[1]	916	779	2,652	2,270
Capitalized interest		(686)	(1,085)	(3,094)	(3,115)
Total interest expense		$ 7,933	$ 6,991	$ 22,430	$ 20,794
[1]	The three months ended September 30, 2015 and 2014 includes $644,000 and $584,000, respectively, of debt discount accretion related to the Notes. The nine months ended September 30, 2015 and 2014 includes $1.9 million and $1.7 million, respectively, of debt discount accretion related to the Notes.

Interest Expense (Schedule of43

Interest Expense (Schedule of Components of Interest Expense) (Parenthetical) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Interest Expense [Abstract]
Accretion of debt discount	$ 644	$ 584	$ 1,900	$ 1,700

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Tax Disclosure [Abstract]
Current income tax benefit or provision	$ 0	$ 0	$ 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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items]
Net (loss) income attributable to common stockholders	$ (191,819)	$ 9,807	$ (312,837)	$ 9,858
Weighted average common shares outstanding basic (shares)	77,628,120	60,006,903	77,453,251	58,982,709
Incremental shares from unvested restricted shares	0	2,614,215	0	2,587,345
Incremental shares from outstanding stock options	0	115,421	0	109,755
Incremental shares from outstanding PBUs	0	662,907	0	626,671
Weighted average common shares outstanding diluted (shares)	77,628,120	63,399,446	77,453,251	62,306,480
Basic (dollars per share)	$ (2.47)	$ 0.16	$ (4.04)	$ 0.0017
Diluted (dollars per share)	$ (2.47)	$ 0.15	$ (4.04)	$ 0.0016
Common shares excluded from denominator as anti-dilutive (shares)	742,432	14,877	230,432	45,203
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)	239,161	14,877	146,253	45,203
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	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)	503,271	0	84,179	0

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Millions	Jun. 09, 2015	Dec. 17, 2010
Gastar Exploration Ltd Vs US Specialty Ins Co and Axis Ins Co
Loss Contingencies [Line Items]
Settlement aggregate amount		$ 21.2
Combined coverage limits under directors and officers insurance		$ 20
Husky Ventures Inc Vs J Russell Porter, Michael A Gerlich, Michael McCown, Keith R Blair, Henry J Hansen and John M Selser Sr | Minimum
Loss Contingencies [Line Items]
Amount of actual damages alleged in which Husky seeks to recover (in excess of $2.0 million)	$ 2

Statement of Cash Flows - Sup47

Statement of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of capitalized amounts	$ 12,699	$ 11,668
Non-cash transactions:
Capital expenditures (excluded from) included in accounts payable and accrued drilling costs	(12,396)	1,601
Capital expenditures included in accounts receivable	0	4,077
Asset retirement obligation included in oil and natural gas properties	276	109
Application of advances to operators	11,113	36,812
Expenses accrued for the issuance of common stock	0	223
Other	$ 0	$ (11)