Gastar Exploration (GST) 10-K 9 Mar 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 06, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
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 Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 129.3
Entity Common Stock, Shares Outstanding		186,124,138

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 71,529	$ 50,074
Accounts receivable, net of allowance for doubtful accounts of $1,953 and $0, respectively	26,883	14,302
Commodity derivative contracts	6,212	15,534
Prepaid expenses	755	5,056
Total current assets	105,379	84,966
Oil and natural gas properties, full cost method of accounting:
Unproved properties, excluded from amortization	67,333	92,609
Proved properties	1,253,061	1,286,373
Total natural gas and oil properties	1,320,394	1,378,982
Furniture and equipment	2,622	3,068
Total property, plant and equipment	1,323,016	1,382,050
Accumulated depreciation, depletion and amortization	(1,131,012)	(1,053,116)
Total property, plant and equipment, net	192,004	328,934
OTHER ASSETS:
Commodity derivative contracts	1,638	9,335
Deferred charges, net	676	985
Advances to operators and other assets	102	331
Other	405	4,944
Total other assets	2,821	15,595
TOTAL ASSETS	300,204	429,495
CURRENT LIABILITIES:
Accounts payable	8,867	2,029
Revenue payable	6,690	5,985
Accrued interest	3,515	3,730
Accrued drilling and operating costs	2,615	2,010
Advances from non-operators	3,504	167
Commodity derivative contracts	338	0
Commodity derivative premium payable	1,654	3,194
Asset retirement obligation	89	89
Other accrued liabilities	2,462	6,764
Total current liabilities	29,734	23,968
LONG-TERM LIABILITIES:
Long-term debt, net	404,493	516,476
Commodity derivative contracts	0	451
Commodity derivative premium payable	969	2,788
Asset retirement obligation	5,443	5,997
Total long-term liabilities	410,905	525,712
Commitments and contingencies (Note 13)
STOCKHOLDERS' EQUITY:
Common stock, par value $0.001 per share; 550,000,000 and 275,000,000 shares authorized at December 31, 2016 and 2015, respectively; 150,377,870 and 80,024,218 shares issued and outstanding at December 31, 2016 and 2015, respectively	150	80
Additional paid-in capital	644,306	571,947
Accumulated deficit	(784,953)	(692,274)
Total stockholders' equity	(140,435)	(120,185)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	300,204	429,495
Series A Preferred Stock
STOCKHOLDERS' EQUITY:
Preferred stock	41	41
Series B Preferred Stock
STOCKHOLDERS' EQUITY:
Preferred stock	$ 21	$ 21

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Jul. 05, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for doubtful accounts	$ 1,953		$ 0	$ 0	$ 507
Preferred stock, shares authorized	40,000,000		40,000,000
Common stock, par value	$ 0.001		$ 0.001
Common stock, shares authorized	550,000,000	550,000,000	275,000,000
Common stock, shares issued	150,377,870		80,024,218
Common stock, shares outstanding	150,377,870		80,024,218
Series A Preferred Stock
Preferred stock, shares authorized	10,000,000		10,000,000
Preferred stock, par value	$ 0.01		$ 0.01
Preferred stock, shares issued	4,045,000		4,045,000
Preferred stock, shares outstanding	4,045,000		4,045,000
Liquidation preference per share	$ 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 per share	$ 25		$ 25

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES:
Oil and condensate	$ 43,011	$ 58,668	$ 82,820
Natural gas	10,854	16,901	47,647
NGLs	7,252	7,136	21,382
Total oil and condensate, natural gas and NGLs revenues	61,117	82,705	151,849
(Loss) gain on commodity derivatives contracts	(2,863)	24,589	19,569
Total revenues	58,254	107,294	171,418
EXPENSES:
Production taxes	1,908	2,877	6,733
Lease operating expenses	20,605	23,728	19,323
Transportation, treating and gathering	1,704	2,187	3,679
Depreciation, depletion and amortization	29,673	62,887	46,180
Impairment of natural gas and oil properties	48,497	426,878	0
Accretion of asset retirement obligation	368	502	506
General and administrative expense	19,445	17,069	16,485
Litigation settlement benefit	(10,100)	0	0
Total expenses	112,100	536,128	92,906
(LOSS) INCOME FROM OPERATIONS	(53,846)	(428,834)	78,512
OTHER (EXPENSE) INCOME:
Interest expense	(35,246)	(30,686)	(27,571)
Investment and other income	31	13	19
Foreign transaction loss	0	0	(7)
(LOSS) INCOME BEFORE PROVISION FOR INCOME TAXES	(89,061)	(459,507)	50,953
Provision for income taxes	0	0	0
NET (LOSS) INCOME	(89,061)	(459,507)	50,953
Dividends on preferred stock	(3,618)	(14,473)	(14,424)
Undeclared cumulative dividends on preferred stock	(10,855)	0	0
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (103,534)	$ (473,980)	$ 36,529
NET (LOSS) INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Basic (in dollars per share)	$ (0.93)	$ (6.11)	$ 0.58
Diluted (in dollars per share)	$ (0.93)	$ (6.11)	$ 0.55
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
Basic (shares)	111,367,452	77,511,677	63,270,733
Diluted (shares)	111,367,452	77,511,677	66,492,589

Consolidated Statement of Stock

Consolidated Statement of Stockholders' Equity (Deficit) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Series A Preferred StockPreferred Stock	Series B Preferred StockPreferred Stock
Balance at beginning of period at Dec. 31, 2013	$ 210,029	$ 61	$ 464,730	$ (254,823)	$ 40	$ 21
Balance at beginning of period (in shares) at Dec. 31, 2013		61,211,658			3,958,160	2,140,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of preferred stock	2,066		2,065		$ 1
Issuance of preferred stock (shares)					86,840
Issuance of common shares - cash, net of offering costs	101,319	$ 17	101,302
Issuance of common shares - cash, net of offering costs (shares)		17,000,000
Issuance of common shares - PBUs vesting, net of forfeitures (shares)		472,189
Issuance of restricted stock	0
Issuance of restricted stock (shares)		601,473
Forfeitures of restricted stock	(4,562)		(4,562)
Forfeitures of restricted stock (shares)		(659,227)
Exercise of stock options, net of forfeitures	15		15
Exercise of stock options, net of forfeitures (shares)		6,717
Stock-based compensation	4,890		4,890
Preferred stock dividends	(14,424)			(14,424)
Net income (loss)	50,953			50,953
Balance at end of period at Dec. 31, 2014	350,286	$ 78	568,440	(218,294)	$ 41	$ 21
Balance at end of period (in shares) at Dec. 31, 2014		78,632,810			4,045,000	2,140,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares - PBUs vesting, net of forfeitures		$ 1	(1)
Issuance of common shares - PBUs vesting, net of forfeitures (shares)		497,636
Issuance of restricted stock		$ 1	(1)
Issuance of restricted stock (shares)		1,426,604
Forfeitures of restricted stock	(1,472)		(1,472)
Forfeitures of restricted stock (shares)		(532,832)
Stock-based compensation	4,981		4,981
Preferred stock dividends	(14,473)			(14,473)
Net income (loss)	(459,507)			(459,507)
Balance at end of period at Dec. 31, 2015	(120,185)	$ 80	571,947	(692,274)	$ 41	$ 21
Balance at end of period (in shares) at Dec. 31, 2015		80,024,218			4,045,000	2,140,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares - cash, net of offering costs	44,813	$ 50	44,763
Issuance of common shares - cash, net of offering costs (shares)		50,000,000
Issuance of common shares under ATM - cash, net of offering costs	24,411	$ 19	24,392
Issuance of common shares under ATM - cash, net of offering costs (shares)		18,606,943
Issuance of common shares - PBUs vesting, net of forfeitures		$ 1	(1)
Issuance of common shares - PBUs vesting, net of forfeitures (shares)		502,593
Issuance of restricted stock		$ 1	(1)
Issuance of restricted stock (shares)		1,764,645
Forfeitures of restricted stock	(713)	$ (1)	(712)
Forfeitures of restricted stock (shares)		(520,529)
Stock-based compensation	3,918		3,918
Preferred stock dividends	(3,618)			(3,618)
Net income (loss)	(89,061)			(89,061)
Balance at end of period at Dec. 31, 2016	$ (140,435)	$ 150	$ 644,306	$ (784,953)	$ 41	$ 21
Balance at end of period (in shares) at Dec. 31, 2016		150,377,870			4,045,000	2,140,000

Consolidated Statement of Stoc6

Consolidated Statement of Stockholders' Equity (Deficit) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2014
Statement Of Stockholders Equity [Abstract]
Issuance of common shares- cash, offering costs	$ 2,687	$ 4,931
Issuance of common shares under ATM- cash, offering costs	$ 557

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income		$ (89,061)	$ (459,507)	$ 50,953
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		29,673	62,887	46,180
Impairment of natural gas and oil properties		48,497	426,878	0
Stock-based compensation		3,918	4,981	4,890
Total loss (gain) on commodity derivatives contracts		2,863	(24,589)	(19,569)
Cash settlements of matured commodity derivative contracts, net		13,110	24,910	(4,901)
Cash premiums paid for commodity derivatives contracts		(565)	(45)	(185)
Amortization of deferred financing costs	[1]	4,980	3,584	3,067
Accretion of asset retirement obligation		368	502	506
Settlement of asset retirement obligation		(307)	(83)	(588)
Loss on sale of furniture and equipment		97	0	0
Changes in operating assets and liabilities:
Accounts receivable		(14,850)	19,333	(12,524)
Prepaid expenses		4,301	(2,973)	(938)
Accounts payable and accrued liabilities		3,713	(4,606)	(2,566)
Net cash provided by operating activities		6,737	51,272	64,325
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of oil and natural gas properties		(59,922)	(148,182)	(155,631)
Reimbursements from (advances to) operators		576	(2,302)	(61,067)
Acquisition of oil and natural gas properties - refund (expenditure)		1,143	(45,575)	4,209
Proceeds from sale of oil and natural gas properties		121,273	47,314	5,530
Proceeds from (payments to) non-operators		3,337	(1,653)	(7,439)
Sale (purchase) of furniture and equipment		73	(58)	(319)
Net cash provided by (used in) investing activities		66,480	(150,456)	(214,717)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common shares, net of issuance costs		69,224	0	101,319
Proceeds from revolving credit facility		0	196,000	103,000
Repayment of revolving credit facility		(115,370)	(41,000)	(58,000)
Proceeds from issuance of preferred stock, net of issuance costs		0	0	2,064
Dividends paid on preferred stock		(3,618)	(14,473)	(14,424)
Deferred financing charges		(1,285)	(805)	(405)
Tax withholding related to restricted stock and PBU vestings		(713)	(1,472)	(4,562)
Other		0	0	15
Net cash (used in) provided by financing activities		(51,762)	138,250	129,007
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		21,455	39,066	(21,385)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		50,074	11,008	32,393
CASH AND CASH EQUIVALENTS, END OF PERIOD		$ 71,529	$ 50,074	$ 11,008
[1]	The years ended December 31, 2016, 2015 and 2014 include $2.8 million, $2.5 million and $2.3 million, respectively, of debt discount accretion related to the Notes.

Description of Business

Description of Business	12 Months Ended
	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Description of Business	1. Gastar Exploration Inc. (“Gastar” or the “Company”) is a pure-play Mid-Continent independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and natural gas liquids (“NGLs”). 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. Gastar holds a concentrated acreage position in what is believed to be the core of the STACK Play, an area of central Oklahoma which is home to multiple oil and natural gas-rich reservoirs including the Meramec and Osage formations within the Mississippi Lime, the Oswego limestone, the Woodford shale and Hunton limestone formations. These formations are what is commonly referred to as the “STACK Play”. On April 8, 2016, Gastar sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for an adjusted sales price of $75.7 million, net of $3.5 million of suspense liability transferred to buyer, with an effective date of January 1, 2016 (the “Appalachian Basin Sale”). 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	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Basis of Presentation The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the U.S.(“GAAP”). The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 17. “Supplemental Oil and Gas Disclosures.” 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). Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate. Preferred Dividends On January 10, 2017, the Company, together with the parties thereto, entered into Amendment No. 10 to the Second Amended and Restated Credit Agreement (“Amendment No. 10”), dated as of January 10, 2017. Amendment No. 10, among other things, permitted the limited payment of certain cash dividends on the Company’s preferred stock, including the dividends declared payable on January 31, 2017, provided that (1) the Company’s borrowing base will be correspondingly reduced in the amount of any such dividend payment and (2) the Company pays down its outstanding indebtedness under the Revolving Credit Facility in the amount of any resulting borrowing base deficiency. Under Amendment No. 10, payment of the declared January 2017 dividend and monthly preferred stock cash dividends through May 2017 was permitted contingent upon the satisfaction of certain conditions, including but not limited to, (1) the absence of any defaults or borrowing base deficiency, (2) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (3) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the Company’s at-the-market sales program). The Company paid all accumulated and unpaid dividends for the period April 2016 to December 2016, as well as the January 2017, preferred dividend payment on January 31, 2017. Under the agreement pursuant to which the Term Loan is issued and the indenture governing the Notes, cash dividend payments on the Company’s outstanding preferred stock are permitted through July 31, 2018 contingent upon the absence of any defaults. From and after August 1, 2018, dividend payments on the Series A and Series B Preferred Stock are permitted subject to the Company’s compliance with a certain fixed charge coverage ratio test. Stockholder Rights Agreement On January 27, 2017, the Company’s board of directors adopted a replacement stockholder rights plan (the “2017 Rights Agreement”) to effectively replace the stockholders rights plan adopted on January 18, 2016 (the “2016 Rights Agreement”). As of January 18, 2017, the 2016 Rights Agreement expired pursuant to its terms. Pursuant to the 2017 Rights Agreement, the Company’s board of directors declared a non-taxable dividend of one preferred share purchase right (each, a “Right”) for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on February 10, 2017. Each Right entitles the registered holder, subject to the terms of the 2017 Rights Agreement to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $10.74, subject to certain adjustments. The purpose of the 2017 Rights Agreement is to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. Ares Investment Transaction On March 3, 2017 (the “Closing Date”), the Company closed the previously announced capital and refinancing transactions (the “Ares Investment Transaction”) with certain funds (the “Purchasers”) affiliated with Ares Management, L.P. (“Ares”). Securities Purchase Agreement On February 16, 2017, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with the Purchasers, pursuant to which the Company issued and sold for cash to the Purchasers (i) $125.0 million aggregate principal amount of its Convertible Notes due 2022 (the “Notes”), which Notes, subject to the receipt of approval of the Company’s stockholders, will be convertible into common stock, par value $0.001 per share of the Company (the “Common Stock”) or, in certain circumstances, cash in lieu of Common Stock or a combination of cash and shares of Common Stock as described below and (ii) 29,408,305 shares of Common Stock for a purchase price of $50.0 million. In addition, an affiliate of Ares concurrently loaned the Company $250.0 million pursuant to a senior secured first-lien term loan as further described below (the “Term Loan”). The proceeds from the sale of the Notes, the Common Stock and the Term Loan were used to fully repay the $69.2 million outstanding on the Company’s revolving credit facility and to satisfy and discharge its $325.0 million of 8.625% senior secured notes due May 2018, which will be redeemed at a price of 102.156% of their principal amount on March 24, 2017, and to pay the expenses from the Ares Investment Transaction. The issuance of Common Stock and the Notes were consummated as a private placement to “accredited investors” (as that term is defined under Rule 501 of Regulation D), exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), in reliance upon Section 4(a)(2) of the Securities Act and Regulation D Rule 506, as a transaction by an issuer not involving a public offering. The issuance of the shares of Common Stock to the Purchasers was priced based on a 30-trading day volume weighted average trading price (the “VWAP”) of $1.7002 per share, determined as of February 15, 2017, the date immediately prior to the signing date of the Purchase Agreement. This resulted in the issuance of 29,408,305 shares of Common Stock to the Purchasers, or approximately 18.8% of the shares of the Company’s 156,715,833 shares of Common Stock issued and outstanding as of January 31, 2017. For so long as the Purchasers, collectively, beneficially own 10% or more of the Common Stock (including for this purpose all shares of Common Stock issuable upon conversion of the Notes), the Purchasers will have certain preemptive rights to purchase their pro rata share of any additional equity securities offered by the Company in the future on similar terms as are offered to other purchasers. On March 2, 2017, the Company entered into Amendment No. 1 to the Purchase Agreement (the “Amendment”) with the Purchasers. The Amendment amended the director nomination rights described below and the requisite ownership thresholds to exclude holders of any warrants or other convertible securities to satisfy the applicable NYSE MKT rules and regulations. Pursuant to the Purchase Agreement, as amended by the Amendment, and so long as the Purchasers beneficially own (excluding ownership of Voting Stock (as defined in the Purchase Agreement) that such person only has the right to acquire) at least 15% of the total outstanding voting power of the Company’s Voting Stock, the Purchasers will be entitled to nominate two directors to an expanded eight-member board of directors of the Company. If the Purchasers beneficially own (excluding ownership of Voting Stock that such person only has the right to acquire) 5% or more, but less than 15%, of the total outstanding voting power of the Company’s Voting Stock, the Purchasers will be entitled to nominate one director to the board of directors of the Company. Term Loan On the Closing Date, the Company entered into the Third Amended and Restated Credit Agreement among the Company, as borrower, the guarantor party thereto, AF V Energy I Holdings, L.P., an affiliate of Ares, as initial lender, and Wilmington Trust, National Association, as administrative agent. The loans made pursuant to the Term Loan bear interest a per annum rate equal to 8.5%, payable on a quarterly basis on each March 1, June 1, September 1 and December 1 of each year, commencing on June 1, 2017. The Term Loan has a scheduled maturity of March 3, 2022. In addition, the Term Loan is subject to an interest “make-whole” and repayment premium, such that any repayment or prepayment of the loans thereunder prior to the stated maturity date shall be subject to the payment of a repayment premium, and depending on the date of such repayment or prepayment, the applicable interest “make-whole” amount, with the amount of such repayment premium decreasing over the life of the Term Loan. The Term Loan is guaranteed by the Company’s domestic subsidiary (excluding certain insignificant subsidiaries) and will be guaranteed by all of the Company’s future domestic subsidiaries formed during the term of the Term Loan. The Term Loan is secured by a first-priority lien on substantially all of the assets of the Company as its subsidiary, excluding certain assets as customary exceptions. The Term Loan contains various customary covenants for credit facilities of this type, including, among others, restrictions on granting liens, incurrence of other indebtedness, payments of certain dividends and other restricted payments, engaging in transactions with affiliates, dispositions of assets and other covenants, in each case subject to certain baskets and exceptions. All outstanding amounts owed under the Term Loan become due and payable upon the occurrence of certain usual and customary events of default, including among others: (i) failure to make payments; (ii) non-performance of covenants and obligations continuing beyond any applicable grace period; and (iii) the occurrence of a change in control of the Company, as defined in the Term Loan. The Company does not expect that the covenants or other provisions of the Term Loan or the Notes will restrict the payment of dividends on the Company’s outstanding preferred stock through July 2018, and, thereafter, such payments will be subject to satisfaction of certain financial conditions. Any future dividends on such preferred stock, however, remain subject to declaration by the Company, and there is no assurance that the Company will declare and pay any future dividends, even if it is permitted to do so under the terms of the Term Loan or the Notes. Indenture and Notes On the Closing Date, the Company entered into an indenture (the “Indenture”) by and among the Company, the subsidiary guarantor named therein, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral trustee, with respect to the Notes. The principal terms of the Notes are governed by the Indenture. Pursuant to the Indenture, the Notes were issued for cash at par, bear interest initially at 6.0% per annum and will mature on March 1, 2022, unless earlier repurchased, redeemed or converted in accordance with the terms of the Indenture. Interest is payable on the Notes on each March 1, June 1, September 1 and December 1 of each year, commencing on June 1, 2017. Subject to receipt of stockholder approval on or before July 3, 2017 of the issuance of Common Stock upon conversion of the above Notes (the “Requisite Stockholder Approval”), the Notes will be convertible at the option of the holder into shares of Common Stock based on an initial conversion rate of 452.4355 shares of Common Stock per $1,000 principal amount of the Notes (which is equivalent to an initial conversion price of approximately $2.21 per share, or 30% above the VWAP per share of Common Stock for the 30 trading days prior to execution of the Purchase Agreement), subject to certain adjustments and the issuance of additional “make-whole” shares under circumstances specified in the Indenture. Subject to certain limitations, the Company will have the right to settle its conversion obligations on the Notes in cash, shares of Common Stock or a combination of cash and shares of Common Stock. If the Company obtains the Requisite Stockholder Approval, then the Company will have the right to redeem the Notes (i) on or after March 3, 2019, if the last reported sale price per share of Common Stock exceeds 150% of the conversion price for periods specified in the Indenture; and (ii) on or after March 1, 2021 without regard to such condition, in each case at cash redemption price equal to the principal amount of the Notes to be redeemed plus accrued interest, if any. The interest rate, conversion rate and other financial terms of the Notes were determined by negotiations between the Company and the Purchasers. The interest rate on the Notes will be subject to an increase in certain circumstances if the Company fails to obtain Requisite Stockholder Approval or to comply with certain obligations under the Registration Rights Agreement (as defined below), or in the case of certain issuances of Common Stock at below $1.7002 per share (subject to adjustment). The Notes will be secured by a second-priority lien on substantially all of the assets of the Company. The Indenture restricts the ability of the Company and certain of its subsidiaries to, among other things: (i) pay dividends or make other distributions in respect of the Company’s capital stock or make other restricted payments; (ii) incur additional indebtedness and issue preferred stock; (iii) make certain dispositions and transfers of assets; (iv) engage in transactions with affiliates; (v) create liens; (vi) engage in certain business activities that are not related to oil and gas; and (vii) impair any security interest. These covenants are subject to a number of exceptions and qualifications. The Indenture provides that a number of events will constitute an Event of Default (as defined in the Indenture), including, among other things: (i) a failure to pay the Notes when due at maturity, upon redemption or repurchase; (ii) failure to pay interest for 30 days; (iii) the Company’s failure to deliver certain notices; (iv) a default in the Company’s obligation to convert the Notes; (v) the Company’s failure to comply with certain covenants relating to merger, consolidation or sale of assets; (vi) the Company’s failure to comply, for 60 days following notice, with any of the other covenants or agreements in the Indenture; (vii) a default, which is not cured within 30 days, by the Company or any Restricted Subsidiaries (as defined in the Indenture) with respect to any mortgages or any indebtedness for money borrowed of at least $15 million; (viii) one or more final judgments against the Company or any of its Restricted Subsidiaries for the payment of at least $15 million; (ix) the Company’s failure to make any payments required under that certain development agreement; (x) causing any Guarantee (as defined in the Indenture) to cease to be in full force and effect; (xi) the cessation to be in full force and effect of any of the collateral agreements related to the Ares Investment Transaction; and (xii) certain events of bankruptcy or insolvency. In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to the Company, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. If Requisite Stockholder Approval is not obtained, then upon any acceleration of the Notes following an Event of Default, holders will be entitled to receive a “make-whole” premium in addition to principal and accrued interest. If stockholders do not approve the conversion rights of the Notes into Common Stock within four months of the Closing Date, the Notes will not be convertible and the interest rate on the Notes will increase in increments to 15% per annum, and will not be redeemable by the Company prior to maturity except upon payment of a “make-whole” redemption premium. If at least a majority of the Notes issued pursuant to the Purchase Agreement cease to be held by affiliates of Ares after receipt of Requisite Stockholder Approval as provided in the Indenture, the liens securing the Notes will be released and substantially all of the restrictive covenants in the Indenture will terminate. Registration Rights Agreement On the Closing Date, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Purchasers, pursuant to which the Company has agreed that the future resale of the Common Stock sold in the Ares Investment Transaction and the shares of Common Stock issued upon conversion of the Notes will be registered under the Securities Act. The Registration Rights Agreement includes a plan of distribution permitting the Purchasers to sell the covered Common Stock by various means, including in open market sales from time to time, pursuant to underwritten offerings or in negotiated sales. The failure to (i) file a registration statement prior to July 3, 2017, (ii) have the registration statement declared effective within four months of the filing date for the Company’s 2016 Annual Report on From 10-K or (iii) thereafter, with certain exceptions, maintain the effectiveness of the registration statement, will result in additional interest accruing on the Notes for so long as they are outstanding. The Company will be required to cooperate in a maximum of four underwritten offerings under the Registration Rights Agreement at the expense of the Company (other than underwriting discounts). Intercreditor Agreement On the Closing Date, Wilmington Trust, National Association, as administrative agent for the priority lien secured parties, and Wilmington Trust, National Association, as the second lien agent for the second lien secured parties, entered into an intercreditor agreement, which was acknowledged and agreed to by the Company and its subsidiary guarantor (the “Intercreditor Agreement”) to govern the relationship of the lenders under the Term Loan and the holders of any other priority lien obligations on the one hand, and the noteholders and holders of any other second lien obligations that the Company may issue in the future, with respect to the sharing of collateral, the priority of the liens thereon and certain other matters. Swap Intercreditor Agreement On the Closing Date, Morgan Stanley Capital Group, Inc., NextEra Energy Marketing, LLC, Cargill, Incorporated, Koch Supply & Trading, LP, (collectively, the “Swap Counterparties”), the Company, the guarantor party thereto, Wilmington Trust, National Association, as administrative agent for the lenders from time to time party to the Term Loan, and Wilmington Trust, National Association, as collateral agent on behalf of the secured parties (the “Collateral Agent”) entered into an intercreditor agreement (the “Swap Intercreditor Agreement”) pursuant to which the Collateral Agent will receive, hold, administer, maintain, enforce and distribute the proceeds of all of the loan obligations, swap obligations and its liens upon the collateral for the benefit of the current and future lenders under the Term Loan and the Swap Counterparties. Principles of Consolidation The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation. Use of estimates in Preparation of Financial Statements The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties. Cash and Cash Equivalents The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $71.5 million and $50.1 million as of December 31, 2016 and 2015, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss. Accounts Receivable Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible. During 2016, the Company determined that a receivable account from a third-party natural gas and NGLs purchaser would no longer be collectible as a result of the third-party purchaser filing for bankruptcy. A summary of the activity related to the allowance for doubtful accounts is as follows: For the years ended December 31, 2016 2015 2014 (in thousands) Allowance for doubtful accounts, beginning of year $ — $ — $ 507 Expense 1,953 — — Reductions/write-offs — — (507 ) Allowance for doubtful accounts, end of year $ 1,953 $ — $ — Oil and Natural Gas Properties The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center. Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations. In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization. The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2016 and 2015 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered. The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted. Asset Retirement Obligation Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations. Furniture and Equipment Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years. Capitalized Interest The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The Notes and Revolving Credit Facility were included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2016. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $3.1 million, $3.9 million and $4.3 million for 2016, 2015 and 2014, respectively. Fair Value of Financial Instruments The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value. Deferred Financing Costs Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense. Deferred financing costs are presented as a direct reduction to the carrying amount of the related debt liability where the debt liability is not a line-of-credit arrangement. The following table indicates deferred charges and related accumulated amortization as of the dates indicated: As of December 31, 2016 2015 Deferred charges $ 2,971 $ 1,686 Accumulated amortization (2,295 ) (701 ) Deferred charges, net $ 676 $ 985 Derivative Instruments and Hedging Activity The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resul

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	3. Property, Plant and Equipment The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of Oklahoma, Pennsylvania and West Virginia. On April 8, 2016, the Company sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in Pennsylvania and West Virginia comprising the Company’s assets in the Appalachian Basin. On January 20, 2017, the Company sold its remaining interest in producing wells and undeveloped acreage in West Virginia, effective January 1, 2017, for $200,000. The Company’s total property, plant and equipment consists of the following: December 31, 2016 2015 (in thousands) Oil and natural gas properties, full cost method of accounting: Unproved properties $ 67,333 $ 92,609 Proved properties 1,253,061 1,286,373 Total oil and natural gas properties 1,320,394 1,378,982 Furniture and equipment 2,622 3,068 Total property and equipment 1,323,016 1,382,050 Impairment of proved natural gas and oil properties (813,314 ) (764,817 ) Accumulated depreciation, depletion and amortization (317,698 ) (288,299 ) Total accumulated depreciation, depletion and amortization (1,131,012 ) (1,053,116 ) Total property and equipment, net $ 192,004 $ 328,934 Included in the Company's oil and natural gas properties are asset retirement costs of $1.5 million and $2.4 million as of December 31, 2016 and 2015, respectively. The following table summarizes the components of unproved properties excluded from amortization for the periods indicated: December 31, 2016 2015 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 1,100 $ 1,533 Acreage acquisition costs 58,857 82,560 Capitalized interest 7,376 8,516 Total unproved properties excluded from amortization $ 67,333 $ 92,609 For the year ended December 31, 2015, management’s evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for natural gas and no current plans to drill or extend leases in the Appalachian Basin, the Company reclassified $14.4 million of unproved properties to proved properties for the year ended December 31, 2015. The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that the Company’s capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense for such period. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation is determined using a mandatory trailing 12-month unweighted arithmetic average of the first-day-of-the-month commodities pricing and costs in effect at the end of the period, each of which are held constant indefinitely (absent specific contracts with respect to future prices and costs) with respect to valuing future net cash flows from proved reserves for this purpose. The 12-month unweighted arithmetic average of the first-day-of-the-month commodities prices are adjusted for basis and quality differentials in determining the present value of the proved reserves. The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials: 2016 Total December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.48 $ 2.28 $ 2.24 $ 2.40 West Texas Intermediate oil price (per Bbl) (1) $ 42.75 $ 41.68 $ 43.12 $ 46.26 Impairment recorded (pre-tax) (in thousands) $ 48,497 $ — $ — $ — $ 48,497 2015 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.59 $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 50.28 $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 426,878 $ 144,760 $ 181,966 $ 100,152 $ — 2014 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 4.35 $ 4.24 $ 4.10 $ 3.99 West Texas Intermediate oil price (per Bbl) (1) $ 94.99 $ 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 could potentially incur further ceiling test impairments in the future should commodities prices decline. However, it is difficult to project future impairment charges in light of numerous variables involved. The Company’s proved reserves estimates and their estimated discounted value and standardized measure will also be impacted by changes in lease operating costs, future development costs, production, exploration and development activities. The ceiling limitation calculation is not intended to be indicative of the fair market value of the Company’s proved reserves or future results. The Company’s estimated proved reserve volumes were 25.6 MMBoe at December 31, 2016 using the SEC-mandated historical twelve-month unweighted average pricing at such date. Development Agreement On October 14, 2016, the Company executed an agreement with STACK Exploration LLC, a Delaware limited liability company (the “Investor”), (the “Development Agreement”) to jointly develop up to 60 Gastar operated wells in the STACK Play in Kingfisher County, Oklahoma (the “Drilling Program”). The Drilling Program will target the Meramec and Osage formations within the Mississippi Lime in a contract area within three townships covering approximately 32,900 gross (19,100 net) undeveloped mineral acres under leases held by the Company. The Company will be the operator of all wells jointly developed under the Development Agreement. Under the Development Agreement, the Investor will fund 90% of the Company’s working interest portion of drilling and completion costs to initially earn 80% of the Company’s working interest in each new well (in each case, proportionately reduced by other participating working interests in the well). As a result, the Company will pay 10% of its working interest portion of such costs for 20% of its original working interest. The Drilling Program wells will be mutually developed in three tranches of 20 wells each. The locations of the first 20 wells, comprised of 18 Meramec formation wells and two Osage formation wells, have been mutually agreed upon by the Company and the Investor. Participation in the second tranche of 20 Drilling Program wells will be at the election of the Investor and the third tranche of 20 wells will require mutual consent. With respect to each 20-well tranche, when the Investor has achieved an aggregate 15% internal rate of return for its investment in the tranche, its interest will be reduced from 80% to 40% of the Company’s original working interest and the Company’s working interest increases from 20% to 60% of the Company’s original working interest. When a tranche internal rate of return of 20% is achieved by the Investor, its working interest decreases to 10% and the Company’s working interest increases to 90% of the working interest originally owned by the Company. Upon completion of a tranche, the Investor has the right, but not the obligation, for a period of six months to cause the Company to purchase the Investor’s interest in the Drilling Program that is not subject to final reversion (the “WI Tail”) for such tranche (the “Investor Put Right”) for fair market value by applying the methodology to determine a 15% discounted present value as defined by the Development Agreement. If the Investor fails to exercise the Investor Put Right within the six-month period after achieving final reversion, then for a period of six months thereafter, the Company shall have the right, but not the obligation, to purchase the WI Tail from the Investor on the same fair market value approach of the Investor Put Right. If final reversion has not been achieved by the eighth anniversary of the spud date of the first well in a given tranche, Investor will, for a period of six months thereafter, have the right to cause us to buy Investor’s then-current interest in such tranche at an agreed upon valuation. As of December 31, 2016, the Company and the Investor had completed four gross wells, all of which were on production, within the first tranche of the Drilling Program. As of March 6, 2017, nine gross wells have been completed, all of which are on production. Canadian County Property Sale On October 19, 2016, the Company entered into a purchase and sale agreement to sell certain non-core leasehold interests in approximately 25,300 net acres of which only 19,100 net acres was ascribed allocated value and interests in 25 gross (11.2 net) wells primarily in northeast Canadian County and also in southeast Kingfisher County, Oklahoma to Red Bluff Resources Operating, LLC (“Red Bluff”) for approximately $71.0 million (of which up to $10.0 million is contingent upon the satisfaction of certain conditions), subject to certain adjustments and with a property sale effective date of August 1, 2016 (“South STACK Play Acreage Sale”). On November 18, 2016, the Company and Red Bluff executed and delivered two amendments to the sale agreement and entered into a relating closing agreement, which, among other things, allocated $1.4 million of the purchase price to producing properties with the remainder of the purchase price to non-producing properties. As of December 31, 2016, the Company had received approximately $48.6 million of sales proceeds from the South STACK Play Acreage Sale. An additional $9.5 million was received subsequent to December 31, 2016, which included $5.0 million of the contingent payment. The remaining sales proceeds are anticipated to be received by July 2017, subject to certain adjustments. Appalachian Basin Sale On February 19, 2016, the Company entered into an agreement to sell substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin Sale for $80.0 million, subject to customary closing adjustments. Pursuant to the agreement, on April 8, 2016, the Company completed the Appalachian Basin Sale for an adjusted sales price of $75.7 million, net of $3.5 million of suspense liability transferred to the buyer. The Appalachian Basin 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 determined to be significant to the full cost pool and did not result in a significant change to the depletion rate. Appalachian Basin Sale Pro Forma Operating Results The following unaudited pro forma results for the years ended December 31, 2016 and 2015 show the effect on the Company’s consolidated results of operations as if the Appalachian Basin Sale had occurred at the beginning of the periods presented. The pro forma results are the result of excluding from the statement of operations of the Company the revenues and direct operating expenses for the properties divested adjusted for (1) the reduction in ARO liabilities and accretion expense for the properties divested, (2) the reduction in depreciation, depletion and amortization expense as a result of the divestiture and (3) the reduction in interest expense as a result of the pay down of debt under the Revolving Credit Facility in conjunction with the closing of the Appalachian Basin Sale. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Years Ended December 31, 2016 2015 (in thousands, except (Unaudited) Revenues $ 55,177 $ 93,783 Net loss $ (98,459 ) $ (464,788 ) Loss per share: Basic $ (0.88 ) $ (6.00 ) Diluted $ (0.88 ) $ (6.00 ) The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Appalachian Basin Sale occurred as presented. In addition, future results may vary significantly from the results reflected in such pro forma information. Husky Acquisition On December 16, 2015, the Company completed the acquisition of additional working and net revenue interests in 103 gross (10.2 net) producing wells and certain undeveloped acreage in the STACK Play and Hunton Limestone formations in its existing AMI from its AMI co-participant Husky Ventures, Inc. (“Husky”) and certain affiliates for an adjusted purchase price of approximately $42.7 million, net of $358,000 of revenue suspense liability assumed by the Company (the “Husky Acquisition”). The adjusted purchase price reflected an adjustment for an acquisition effective date of July 1, 2015 and included a $4.3 million deposit into escrow pending the resolution of title defects by the seller and the purchase of overrides recorded in other assets at December 31, 2015. Additionally, the Company conveyed approximately 11,000 net non-core, non-producing acres in Blaine, Major and Kingfisher Counties, Oklahoma to the sellers. As of December 31, 2016, all title defects had been resolved by the seller and the escrow funds had been released. In connection with the acquisition, the AMI participation agreements with the Company’s AMI co-participant were dissolved. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $1.5 million of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company’s preliminary assessment of the fair value of the Husky Acquisition assets resulted in a fair market valuation of $44.6 million. As the fair market valuation varied less than 6% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation. The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Husky Acquisition (in thousands): Consideration: Cash consideration $ 42,085 Conveyance of undeveloped acreage — Total purchase price $ 42,085 Estimated Fair Value of Assets Acquired: Unproved properties $ 27,875 Proved properties 15,592 Other (1,382 ) Total assets acquired $ 42,085 Husky Acquisition Unaudited Pro Forma Operating Results The following unaudited pro forma results for the year ended December 31, 2015 shows the effect on the Company’s consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) additional depreciation, depletion and amortization expense as a result of the Company’s increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Year Ended December 31, 2015 (in thousands, except (Unaudited) Revenues $ 115,147 Net loss $ (470,874 ) Loss per share: Basic $ (6.07 ) Diluted $ (6.07 ) The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Husky Acquisition occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information. Mid-Continent Divestiture On July 6, 2015, the Company sold certain non-core assets comprised of 38 gross (16.7 net) producing wells and approximately 29,500 gross (19,200 net) acres in Kingfisher County, Oklahoma for an adjusted purchase price of $46.5 million. 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.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	4. Long-Term Debt Ares Investment Transaction On February 16, 2017, the Company entered into a Purchase Agreement with Purchasers affiliated with Ares pursuant to which the Company will issue and sell for cash to the Purchasers (i) $125.0 million aggregate principal amount of its Notes due 2022 sold at par, which Notes, subject to the receipt of approval of the Company’s stockholders, will be convertible into Common Stock or, in certain circumstances, cash in lieu of Common Stock or a combination thereof as described below and (ii) 29,408,305 shares of Common Stock for a purchase price of $50.0 million. In addition, an affiliate of Ares has agreed to concurrently loan the Company $250.0 million pursuant to a first lien secured Term Loan. The Company completed the Ares Investment Transaction on March 3, 2017. Proceeds from the sale of the Notes, the Common Stock and the Term Loan will be used to fully repay and redeem the Company’s existing $69.2 million Revolving Credit Facility and its $325.0 million senior secured notes due May 2018. On March 3, 2017, the Company entered the Term Loan. The loans made pursuant to the Term Loan bear interest at a per annum rate equal to 8.5%, payable on a quarterly basis on each March 1, June 1, September 1 and December 1 of each year, commencing June 1, 2017. The Term Loan has a scheduled maturity of March 3, 2022. In addition, the Term Loan is subject to an interest “make-whole” and repayment premium, such that any repayment or prepayment of the loans thereunder prior to the stated maturity date shall be subject to the payment of a repayment premium, and depending on the date of such repayment or prepayment, the applicable interest “make-whole” amount, with the amount of such repayment premium decreasing over the life of the Term Loan. The Term Loan is guaranteed by all of the Company's future domestic subsidiaries and will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Term Loan. The Term Loan is secured by a first-priority lien on substantially all of the assets of the Company and its subsidiaries, excluding certain assets as customary exceptions. The Term Loan contains various customary covenants for credit facilities of this type, including, among others, restrictions on granting liens, incurrence of other indebtedness, payments of certain dividends and other restricted payments, engaging in transactions with affiliates, dispositions of assets and other, in each case subject to certain baskets and exceptions; All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including among others: • Failure to make payments; • Non-performance of covenants and obligations continuing beyond any applicable grace period; and • The occurrence of a change in control of the Company, as defined in the Term Loan. The issuance of Common Stock and the Notes will be consummated as a private placement to “accredited investors” (as that term is defined under Rule 501 of Regulation D), exempt from registration under the Securities Act, in reliance upon Section 4(a)(2) of the Securities Act and Regulation D Rule 506, as a transaction by an issuer not involving a public offering. 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”). The Revolving Credit Facility had a scheduled maturity of November 14, 2017. On January 10, 2017, the Company, together with the parties thereto, entered into Amendment No. 10, which amended the Revolving Credit Facility to, among other things, permit the payment of certain cash dividends on its preferred stock, including the dividends declared payable on January 31, 2017, provided that (i) the Company’s borrowing base will be correspondingly reduced in the amount of any such dividend payment and (ii) the Company pays down its outstanding indebtedness under the Revolving Credit Facility in the amount of any resulting borrowing base deficiency. Under Amendment No. 10, payment of the declared January 2017 dividend and monthly preferred stock cash dividends through May 2017 is permitted contingent upon the satisfaction of certain conditions, including but not limited to, (i) the absence of any defaults or borrowing base deficiency, (ii) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (iii) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the Company’s at-the-market issuance sales agreement with a third-party sales agent to sell, from time to time, shares of the Company’s common stock (the “ATM Program”). Under Amendment No. 10, the Company also agreed to pay down indebtedness under its Revolving Credit Facility by at least an additional $8.1 million by April 30, 2017, which is anticipated to be paid out of proceeds received by such date from the South STACK Play Acreage Sale. On March 3, 2017, the Company used a portion of the net proceeds from the Ares Investment Transaction to fully repay all of the $69.2 million borrowings outstanding under the Revolving Credit Facility (which was terminated on such date). Senior Secured Notes At December 31, 2016, the Company had $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Former Notes”) outstanding under an indenture (the “Former 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 Former Notes bore interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013. Effective May 17, 2016, Wells Fargo Bank, National Association resigned as Trustee and Collateral Agent and Wilmington Trust was appointed Trustee and Collateral Agent pursuant to the Former Indenture. A summary of the Notes balance for the periods indicated is as follows: December 31, 2016 2015 (in thousands) Notes, principal balance $ 325,000 $ 325,000 Less: Unamortized discounts (4,342 ) (7,151 ) Deferred financing costs (795 ) (1,373 ) Notes, net $ 319,863 $ 316,476 On March 3, 2017, the redemption price plus interest of all of the Company’s outstanding $325.0 million principal of 8 5/8% senior secured notes due 2018 (the “Former Notes”) was funded to satisfy and discharge the Former Notes from a portion of the net proceeds from the Ares Investment Transaction, which have been irrevocably called for redemption on March 24, 2017. Notes. On March 3, 2017, the Company issued for cash at par $125.0 million principal amount of the Notes under an indenture (the “Indenture”) by and among the Company, the subsidiary guarantor named therein, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral trustee. The Notes bear interest at 6.0% per annum and will mature on March 1, 2022, unless earlier repurchased, redeemed or converted in accordance with the terms of the Indenture prior to such date. Interest is payable on the Notes on each March 1, June 1, September 1 and December 1 of each year, commencing June 1, 2017. If holders of issued and outstanding common stock (other than shares recently issued to funds managed by affiliates of Ares) approve the conversion rights of the Notes on or before July 3, 2017 in a manner satisfactory to meet the requirements of The NYSE MKT (the “Requisite Stockholder Approval”), the Notes will become convertible at the option of the holder into shares of common stock based on an initial conversion price of $2.2103 per share, subject to certain adjustments and the issuance of additional “make-whole” shares under certain circumstances specified in the Indenture. Subject to certain limitations, the Company will have the right to settle its conversion obligations on the Notes in common stock, or in cash or a combination thereof. If the Company obtains the Requisite Stockholder Approval, then the Company will have the right to redeem the Notes (i) on or after March 3, 2019 if the common stock trades above 150% of the conversion price for periods specified in the Indenture; and (ii) on or after March 1, 2021 without regard to such condition, in each case at par plus accrued interest. If the Requisite Stockholder Approval is not obtained on or before July 3, 2017, the Notes will not be convertible and the interest rate payable on the Notes will increase in increments to 15.0% per annum, and will not be redeemable by the Company prior to maturity except upon payment of a “make-whole” redemption premium. The interest rate on the Notes will also be subject to an increase in certain circumstances if the Company fails to comply with certain obligations under the Registration Rights Agreement (as defined below), or in the case of certain issuances of common stock at below the initial reference price of $1.7002 per share. The Notes are secured by a second-priority lien on substantially all of the assets of the Company. The Indenture restricts the ability of the Company and certain of its subsidiaries to, among other things: (i) have an affiliate of the Company acquire the Notes; (ii) pay dividends or make other distributions in respect of the Company’s capital stock or make other restricted payments; (iii) incur additional indebtedness and issue preferred stock; (iv) make certain dispositions and transfers of assets; (v) engage in transactions with affiliates; (vi) create liens; (vii) engage in certain business activities that are not related to oil and gas; and (viii) impair any security interest. These covenants are subject to a number of exceptions and qualifications.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	5. Asset Retirement Obligation A summary of the activity related to the asset retirement obligation is as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Asset retirement obligation, beginning of year $ 6,086 $ 5,557 $ 6,063 Liabilities incurred during period 196 302 305 Liabilities settled during period (90 ) (37 ) (704 ) Accretion expense 368 502 506 Revision in previous estimates and other 17 178 32 Deletions related to property disposals (1,045 ) (416 ) (645 ) Asset retirement obligation, end of year $ 5,532 $ 6,086 $ 5,557 As of December 31, 2016, the current portion of the Company’s asset retirement obligation was $89,000 and was recorded in current liabilities on the consolidated balance sheet.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	6. The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties, which are Level 3 inputs. For the year ended December 31, 2015, management’s evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no plans to drill or extend leases in the Appalachian Basin during 2015, the Company reclassified $14.4 million of unproved properties to proved properties for the year ended December 31, 2015. As no other fair value measurements are required to be recognized on a non-recurring basis at December 31, 2016, no additional disclosures are provided at December 31, 2016. As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows: • Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds. • Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. • Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge oil, natural gas and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2016 and 2015 periods. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015: Fair value as of December 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 71,529 $ — $ — $ 71,529 Commodity derivative contracts — — 7,850 7,850 Liabilities: Commodity derivative contracts — — (338 ) (338 ) Total $ 71,529 $ — $ 7,512 $ 79,041 Fair value as of December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 50,074 $ — $ — $ 50,074 Commodity derivative contracts — — 24,869 24,869 Liabilities: Commodity derivative contracts — — (451 ) (451 ) Total $ 50,074 $ — $ 24,418 $ 74,492 The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2016 and 2015. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2016 and 2015. For the Years Ended December 31, 2016 2015 (in thousands) Balance at beginning of period $ 24,418 $ 27,502 Total (losses) gains included in earnings (2,863 ) 24,589 Purchases 565 1,326 Issuances (165 ) (1,313 ) Settlements (1) (14,443 ) (27,686 ) Balance at end of period $ 7,512 $ 24,418 The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2016 and 2015 $ (13,622 ) $ (1,890 ) (1) Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations. At December 31, 2016, the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at December 31, 2016 was $403.1 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximated the current market rate (Level 2). The estimated fair value of the Company’s long-term debt at December 31, 2015 was $377.5 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximated the current market rate (Level 2). The Company has consistently applied the valuation techniques discussed above in all periods presented. The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivative Instruments and Hedging Activity.”

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activity	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activity	7. The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk. All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in gain (loss) on commodity derivatives contracts. For the years ended December 31, 2016 and 2015, the Company reported losses of $13.6 million and $1.9 million, respectively, in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. For the year ended December 31, 2014, the Company reported a gain of $23.9 million in the consolidated statement of operations related to the change in the fair value of its commodity derivative instruments. As of December 31, 2016, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume (1) Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in Bbls) 2017 Costless three-way collar 280 102,200 $ — $ 80.00 $ 65.00 $ 97.25 2017 Costless three-way collar 250 91,250 $ — $ 80.00 $ 60.00 $ 98.70 2017 (2) Protective spread 200 36,200 $ 60.00 $ — $ 42.50 $ — 2017 Put spread 500 182,500 $ — $ 82.00 $ 62.00 $ — 2017 (2) Protective spread 200 36,200 $ 57.50 $ — $ 42.50 $ — 2017 (2) Fixed price swap 300 54,300 $ 50.10 $ — $ — $ — 2017 (3) Costless three-way collar 200 36,800 $ — $ 60.00 $ 42.50 $ 85.00 2017 (3) Costless three-way collar 200 36,800 $ — $ 57.50 $ 42.50 $ 76.13 2017 (4) Fixed price swap 200 18,000 $ 50.05 $ — $ — $ — 2017 (2) Fixed price swap 275 49,775 $ 51.25 $ — $ — $ — 2018 (5) Put spread 425 103,275 $ — $ 80.00 $ 60.00 $ — (1) Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. (2) For the period January to June 2017. (3) For the period July to December 2017. (4) For the period January to March 2017. (5) For the period January to August 2018. As of December 31, 2016, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in MMBtu’s) 2017 Costless three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 2017 (1) Costless collar 2,000 180,000 $ — $ 3.10 $ — $ 3.78 2017 (2) Fixed price swap 1,500 321,000 $ 3.30 $ — $ — $ — 2018 Costless three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 (1) For the period January to March 2017. (2) For the period April to October 2017. As of December 31, 2016, all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institution, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features. In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period January 2017 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: For 2016 2015 (in thousands) Current commodity derivative premium put payable $ 1,654 $ 3,194 Long-term commodity derivative premium payable 969 2,788 Total unamortized put premium liabilities $ 2,623 $ 5,982 For the Years Ended December 31, 2016 2015 (in thousands) Put premium liabilities, beginning balance $ 5,982 $ 7,183 Settlement of put premium liabilities (3,194 ) (2,295 ) Additional put premium liabilities (165 ) 1,094 Put premium liabilities, ending balance $ 2,623 $ 5,982 The following table provides information regarding the amortization of the deferred put premium liabilities by year as of December 31, 2016: Amortization (in thousands) January to December 2017 $ 1,654 January to December 2018 969 Total unamortized put premium liabilities $ 2,623 Additional Disclosures about Derivative Instruments and Hedging Activities The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value December 31, Balance Sheet Location 2016 2015 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 6,212 $ 15,534 Commodity derivative contracts Other assets 1,638 9,335 Commodity derivative contracts Current liabilities (338 ) — Commodity derivative contracts Long-term liabilities — (451 ) Total derivatives not designated as hedging instruments $ 7,512 $ 24,418 Amount of (Loss) Gain Recognized in Income on Derivatives For the Years Ended December 31, Location of (Loss) Gain Recognized in Income on Derivatives 2016 2015 2014 (in thousands) Derivatives Commodity derivative contracts (Loss) gain on commodity derivatives contracts $ (2,863 ) $ 24,589 $ 19,569 Total $ (2,863 ) $ 24,589 $ 19,569

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2016
Stockholders Equity Note [Abstract]
Capital Stock	8. Capital Stock Common Stock On January 31, 2014, Parent entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Parent merged with and into Gastar Exploration USA, Inc. (“Gastar USA”), a direct subsidiary of Parent, as part of a reorganization to eliminate Parent’s holding company corporate structure. Pursuant to the Merger Agreement, shares of Parent’s common stock were converted into the right to receive an equal number of shares of common stock of Gastar USA, which together with its subsidiary, owns and continues to conduct business in substantially the same manner as it was being conducted by Parent and its subsidiaries immediately prior to the merger. On September 24, 2014, the Company sold 17,000,000 shares of its common stock in an underwritten public offering pursuant to the Company’s effective Registration Statement on Form S-3 at a price of $6.25 per share, or $106.3 million before offering costs and expenses. The Company received approximately $101.3 million of proceeds from the offering, net of estimated offering costs and expenses of approximately $5.0 million. On May 7, 2015, the Company entered into the ATM Program. The shares were issued pursuant to the Company’s then-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 year ended December 31, 2016, 18,606,943 shares were sold through the ATM program for net proceeds of $24.4 million. For the period January 1, 2017 to February 20, 2017, the Company sold 5,447,919 shares through the ATM program for net proceeds of $8.3 million. The ATM Program expired on February 24, 2017. On May 12, 2016, the Company sold 50,000,000 shares of its common stock in an underwritten public offering at a price of $0.95 per share, or $47.5 million before offering costs and expenses. The Company received approximately $44.8 million of proceeds from the offering, net of offering costs and expenses of approximately $2.7 million. On June 14, 2016, the Company’s stockholders approved an amendment to the Company’s certificate of incorporation to increase the number of authorized shares of common stock from 275,000,000 to 550,000,000, which amendment became effective on July 5, 2016. On February 16, 2017, the Company entered into the Purchase Agreement with purchasers affiliated with Ares, pursuant to which the Stockholder Rights Agreement On January 18, 2016, the Company’s board of directors adopted the 2016 Rights Agreement pursuant to which the Company declared a dividend of one right for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on January 28, 2016. Each right entitled the holder, subject to the terms of the 2016 Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Preferred Stock at a price of $6.96, subject to certain adjustments. The purpose of the 2016 Rights Agreement was to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. The 2016 Rights Agreement expired on January 18, 2017. On January 27, 2017, the Company’s board of directors adopted the 2017 Rights Agreement pursuant to which the Company declared a dividend of one Right for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on February 10, 2017. Each Right entitles the holder, subject to the terms of the 2017 Rights Agreement, to purchase one one-thousandth of a share of Series C Preferred Stock at a price of $10.74, subject to certain adjustments. The purpose of the 2017 Rights Agreement is to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. The Rights generally become exercisable on the earlier of (i) ten business days after any person or group obtains beneficial ownership of 4.95% of the Company’s outstanding common stock (an “Acquiring Person”) or (ii) ten business days after commencement of a tender or exchange offer resulting in any person or group becoming an Acquiring Person. The exercise price payable, and the number of shares of Series C Preferred Stock or other securities or property issuable, upon exercise of the Rights are subject to adjustment from time to time to prevent dilution. In the event that, after a person or a group has become an Acquiring Person, the Company is acquired in a merger or other business combination transaction (or 50% or more of the Company’s assets or earning power are sold), proper provision will be made so that each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then-current exercise price of the Right, that number of shares of common stock of the acquiring company having a market value at the time of that transaction equal to two times the exercise price. The Company may redeem the Rights in whole, but not in part, at any time before a person or group becomes an Acquiring Person at a price of $0.001 per Right, subject to adjustment. At any time after any person or group becomes an Acquiring Person, the Company may generally exchange each Right in whole or in part at an exchange ratio of two shares of common stock per outstanding Right, subject to adjustment. The Rights will expire prior to the earliest of (i) January 27, 2020 or such later day as may be established by the Board prior to the expiration of the Rights, provided that the extension is submitted to the Company’s stockholders for ratification at the next annual meeting of stockholders of the Company succeeding such extension; (ii) the time at which the Rights are redeemed pursuant to the 2017 Rights Agreement; (iii) the time at which the Rights are exchanged pursuant to the 2017 Rights Agreement; (iv) the time at which the Rights are terminated upon the occurrence of certain transactions; (v) the close of business on the first day after the Company’s 2017 annual meeting of stockholders, if approval by the stockholders of the Company of the 2017 Rights Agreement has not been obtained at such meeting; (vi) the close of business on the effective date of the repeal of Section 382 of the Tax Code, if the Board determines that the 2017 Rights Agreement is no longer necessary or desirable for the preservation of Tax Benefits; and (vii) the close of business on the first day of a taxable year of the Company to which the Board determines that no Tax Benefits are available to be carried forward. The Series C Preferred Stock is not redeemable by the Company and has certain voting rights and dividend and liquidation privileges. Preferred Stock Pursuant to the Company’s certificate of incorporation, the Company has 40,000,000 shares of preferred stock authorized. The Company has designated 10,000,000 of such shares to constitute its 8.625% Series A Cumulative Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 of such shares to constitute its 10.75% Series B Cumulative Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share. Series A Preferred Stock At December 31, 2016, there were 4,045,000 shares of 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 paid monthly dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference through March 2016. Effective March 9, 2016, the Revolving Credit Facility prohibited the payment of cash dividends on the Company’s preferred stock commencing April 2016. Pursuant to Amendment No. 10 to the Company’s Revolving Credit Facility, on January 10, 2017, the Company declared a special cash dividend on the Series A Preferred Stock to pay in full all accumulated and unpaid cash dividends accrued since April 1, 2016 at an annualized 8.625% through the payment date. The Series A Preferred Stock January 2017 dividend was payable on January 31, 2017 to holders of record at the close of business on January 20, 2017. Under Amendment No. 10 to the Company’s Revolving Credit Facility, payment of the declared Series A Preferred Stock January 2017 dividend and monthly preferred stock cash dividends through May 2017 are permitted contingent upon the satisfaction of certain conditions, including but not limited to, (i) the absences of any defaults or borrowing base deficiency, (ii) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (iii) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the ATM Program). Dividends on the Series A Preferred Stock accumulate regardless of whether any such dividends are declared. If the Company fails to pay full cash dividends in four calendar quarters, whether consecutive or non-consecutive, then commencing in the calendar month following the first month in such fourth calendar quarter in which cash dividends are not paid in full, and until accumulated dividends are paid in full for four calendar quarters with the last two calendar quarters’ dividends paid in cash, (i) the fixed dividend rate of Series A Preferred Stock each increases by 2.00% per annum, (ii) the Company may be required to issue a dividend of common stock to pay accrued and unpaid dividends, if such dividends are not paid in cash, provided it has sufficient surplus to pay such a dividend under state law, and (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company. Under certain circumstances, “pay in kind” dividends of additional shares of Series A Preferred Stock may be payable in lieu of cash or common stock dividends. For the years ended December 31, 2016, 2015 and 2014, the Company recognized dividends of $8.7 million, $8.7 million and $8.7 million, respectively, for the Series A Preferred Stock. As of December 31, 2016, accumulated and unpaid dividends on the outstanding Series A Preferred Stock aggregated to $6.5 million, or $1.6171875 per share. The accumulated and unpaid Series A Preferred Stock dividends were declared on January 10, 2017 and paid to holders of record on January 31, 2017. Series B Preferred Stock At December 31, 2016, there were 2,140,000 shares of the Series B Preferred Stock issued and outstanding with a $25.00 per share liquidation preference. The Series B Preferred Stock ranks senior to the Company’s common stock and on parity with Series A Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock. Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at the Company’s option for $25.00 per share in cash. Following a change in ownership or control, the Company will have the option to redeem the Series B Preferred Stock within 90 days of the occurrence of the change in control, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If the Company does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into the Company's common stock based upon on an average common stock trading price then in effect but limited to an aggregate of 11.5207 shares of the Company’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If the Company exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption. There is no mandatory redemption of the Series B Preferred Stock. The Company paid monthly dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference through March 2016. Effective March 9, 2016, the Revolving Credit Facility prohibited the payment of cash dividends on the Company’s preferred stock commencing April 2016. Pursuant to Amendment No. 10 to the Company’s Revolving Credit Facility, on January 10, 2017, the Company declared a special cash dividend on the Series B Preferred Stock to pay in full all accumulated and unpaid cash dividends accrued since April 1, 2016 at an annualized 10.75% through the payment date. The Series B Preferred Stock January 2017 dividend was payable on January 31, 2017 to holders of record at the close of business on January 20, 2017. Under Amendment No. 10 to the Company’s Revolving Credit Facility, payment of the declared Series B Preferred Stock January 2017 dividend and monthly preferred stock cash dividends through May 2017 are permitted contingent upon the satisfaction of certain conditions, including but not limited to, (i) the absences of any defaults or borrowing base deficiency, (ii) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (iii) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the ATM Program). Dividends on the Series B Preferred Stock will accumulate regardless of whether any such dividends are declared. If the Company fails to pay full cash dividends in four calendar quarters, whether consecutive or non-consecutive, then commencing in the calendar month following the first month in such fourth calendar quarter in which cash dividends are not paid in full, and until accumulated dividends are paid in full for four calendar quarters with the last two calendar quarters’ dividends paid in cash, (i) the fixed dividend rate of Series B Preferred Stock each increases by 2.00% per annum, (ii) the Company may be required to issue a dividend of common stock to pay accrued and unpaid dividends, if such dividends are not paid in cash, provided it has sufficient surplus to pay such a dividend under state law, and (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company. Under certain circumstances, “pay in kind” dividends of additional shares of Series B Preferred Stock may be payable in lieu of cash or common stock dividends. For the years ended December 31, 2016, 2015 and 2014, the Company recognized dividends of $5.8 million, $5.8 million and $5.8 million, respectively, for the Series B Preferred Stock. As of December 31, 2016, accumulated and unpaid dividends on the outstanding Series B Preferred Stock aggregated to $4.3 million, or $2.0158686 per share. The accumulated and unpaid Series B Preferred Stock dividends were declared on January 10, 2017 and paid to holders of record on January 31, 2017. Other Share Issuances The following table provides information regarding the issuances and forfeitures of the Company's common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated: For the Years Ended December 31, 2016 2015 Other stock issuances: Shares of restricted common stock granted 1,764,645 1,426,604 Shares of restricted common stock vested 1,487,269 1,422,670 Shares of common stock issued pursuant to PBUs vested, net of forfeitures of 207,891 shares and 212,858 shares, respectively 502,593 497,636 Shares of restricted common stock surrendered upon vesting/exercise (1) 392,094 413,333 Shares of restricted common stock forfeited 128,435 119,499 (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. In connection with the merger, Parent’s 2006 Long-Term Stock Incentive Plan was assumed by Gastar Exploration Inc. and, effective as of the merger, was amended, restated and renamed the “Gastar Exploration Inc. Long-Term Incentive Plan” (as amended, the “LTIP”). Shares Reserved At December 31, 2016, the Company had 214,600 shares of common stock reserved for the exercise of stock options and 1,475,730 shares reserved for the settlement of PBUs.

Equity Compensation Plans

Equity Compensation Plans	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity Compensation Plans	9. Equity Compensation Plans Share-Based Compensation Plan The vesting period for recent restricted common stock grants has been one year for directors and three years for employees, vesting annually from the date of grant in equal proportions. On June 12, 2014, the Company’s stockholders approved the LTIP. The approved amendment to the LTIP, effective April 24, 2014, among other things, increased the number of shares reserved for issuance under the LTIP by 3,000,000 shares. The LTIP permits us to issue stock options, stock appreciation rights, bonus stock awards and any other type of award (including PBUs, which are consistent with the LTIP’s purpose to directors, officers and employees of the Company and its subsidiaries. At December 31, 2016, 1,590,327 shares of common stock were available for future stock-based compensation grants under the LTIP. All shares of common stock issued upon the exercise of stock option grants or vesting of restricted stock grants and PBUs are authorized, issued by the Company and are fully paid and non-assessable. Stock Options There were no stock options granted during the years ended December 31, 2016, 2015 and 2014. However, in prior years, the Company issued stock options as a component of its equity compensation program and the fair value of such stock options grants were estimated using the Black-Scholes Merton valuation model. As of December 31, 2016, all stock options were vested. The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2016: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at December 31, 2015 866,600 $ 11.75 Granted — — Exercised — — Canceled/Expired (571,000 ) 14.77 Forfeited (81,000 ) 8.75 Outstanding at December 31, 2016 214,600 $ 4.87 Options vested and exercisable at December 31, 2016 214,600 $ 4.87 1.98 $ — There was no unrecognized expense as of December 31, 2016 for all outstanding options. Restricted Shares The Company has granted restricted shares of common stock which vest based upon continued service or certain other events. The vesting period for recent restricted common stock grants has been from one to three years, but generally has been over three years, except for grants to Company directors that vest in one year, vesting annually from the date of grant in equal proportions. The following table summarizes information related to restricted shares at December 31, 2016: Shares Weighted Average Fair Value per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding non-vested restricted shares at December 31, 2015 2,296,349 $ 2.63 Granted 1,764,645 1.19 Vested (1,487,269 ) 2.37 Forfeited (128,435 ) 1.88 Outstanding non-vested restricted shares at December 31, 2016 2,445,290 $ 1.79 1.49 $ 3,790 The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands, except per share data) Weighted average grant date fair value per restricted share $ 1.19 $ 2.40 $ 5.85 Total fair value of restricted shares vested $ 3,530 $ 3,794 $ 3,497 For the year ended December 31, 2016, the Company recognized $2.7 million of compensation expense associated with restricted share awards. Unrecognized compensation expense as of December 31, 2016 for all outstanding restricted share awards is $1.1 million and will be recognized over a weighted average period of 1.33 years. Performance Based Units Commencing 2013, a portion of long-term incentive grants to Company management were in the form of PBUs. The PBUs represent a contractual right to receive shares of the Company's common stock, an amount of cash equal to the fair market value of a share of the Company's common stock, or a combination of shares of the Company's common stock and cash as of the date of settlement based on the number of PBUs to be settled. The settlement of PBUs may range from 0% to 200% of the targeted number of PBUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PBUs granted prior to 2015 vest equally and settlement is determined annually over a three-year period. The PBUs granted in 2015 and 2016 cliff vest at the end of a three-year period. Any PBUs not vested at each measurement date will expire. Compensation expense associated with PBUs is based on the grant date fair value of a single PBU as determined using a Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PBUs with shares of the Company's common stock at each measurement date, the PBU awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the PBU award. The table below provides a summary of PBUs as of the date indicated: PBUs Weighted Average Fair per Unit Unvested PBUs at December 31, 2015 1,283,167 $ 3.24 Granted 801,397 1.62 Vested (448,634 ) 2.76 Forfeited (160,200 ) 3.40 Unvested PBUs at December 31, 2016 1,475,730 $ 2.49 For the year ended December 31, 2016, the Company recognized $1.2 million of compensation expense associated with the PBUs. As of December 31, 2016, the Company had $1.6 million of total unrecognized expense for the PBUs to be recognized over a weighted average period of 1.65 years. Stock-Based Compensation Expense For the years ended December 31, 2016, 2015 and 2014, the Company recorded stock-based compensation expense for restricted shares, PBUs, and stock options granted using the fair-value method of $3.9 million, $5.0 million and $4.9 million, respectively. All stock-based compensation costs were expensed and not tax affected, as the Company currently records no U.S. income tax expense. As of December 31, 2016, the Company had approximately $2.7 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods: Amount (in thousands) 2017 $ 1,913 2018 717 2019 56 Total $ 2,686

Interest Expense

Interest Expense	12 Months Ended
	Dec. 31, 2016
Interest Expense [Abstract]
Interest Expense	10. The following tables summarize the components of the Company’s interest expense for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands) Interest expense: Cash and accrued $ 33,368 $ 30,981 $ 28,851 Amortization of deferred financing costs (1) 4,980 3,584 3,067 Capitalized interest (3,102 ) (3,879 ) (4,347 ) Total interest expense $ 35,246 $ 30,686 $ 27,571 (1)

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	11. Income Taxes The following table summarizes the components of the Company’s (loss) income before income taxes for the periods indicated: For the Year Ended December 31, 2016 2015 2014 (in thousands) United States $ (89,061 ) $ (459,507 ) $ 50,953 Total income (loss) before income taxes $ (89,061 ) $ (459,507 ) $ 50,953 The Company did not report any current provision for income taxes for the years ended December 31, 2016, 2015 and 2014. The Company had no deferred income tax expense (benefit) for the years ended December 31, 2016, 2015 and 2014. The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands) Expected income tax provision (benefit) at statutory rate $ (31,172 ) $ (160,827 ) $ 17,833 State tax, tax effected (1,408 ) (7,799 ) 803 Stock-based compensation expense (benefit) 1,995 255 (1,291 ) Non-deductible compensation 178 — — Other 693 17 38 Other changes in valuation allowance 29,714 168,354 (17,383 ) Actual income tax provision $ — $ — $ — The components of the Company’s U.S. deferred taxes are as follows: As of December 31, 2016 2015 (in thousands) Deferred tax asset (liability): Capital assets $ 33,131 $ 10,485 Stock-based compensation 2,499 4,243 Net operating loss carry forwards 196,775 187,963 Foreign tax credit carry forwards 50,681 50,681 Valuation allowance (283,086 ) (253,372 ) Net deferred tax asset $ — $ — The Company has approximately $536.2 million of net operating loss carry forwards as of December 31, 2016, which, if not utilized, will expire between 2030 and 2036. For U.S. federal income tax purposes, as of December 31, 2016, the Company has foreign tax credit carry forwards of $50.7 million, which, if not utilized, will expire in 2019. The utilization of the net operating loss carry forward and the foreign tax credit carry forward are dependent on the Company generating future taxable income and U.S. tax liability, as well as other factors. Current authoritative guidance requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2016, the Company did not have any material unrecognized tax benefits that, if recognized, would affect the effective tax rate. The Company is subject to examination of income tax filings in the U.S. and various state jurisdictions for the periods 2010 and Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

Earnings per Share

Earnings per Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings per Share	12. Earnings per Share In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. For the Years Ended December 31, 2016 2015 2014 (in thousands, except per share and share data) Net (loss) income attributable to common stockholders $ (103,534 ) $ (473,980 ) $ 36,529 Weighted average shares of common stock outstanding - basic 111,367,452 77,511,677 63,270,733 Incremental shares from unvested restricted shares — — 2,451,903 Incremental shares from outstanding stock options — — 97,491 Incremental shares from outstanding PBUs — — 672,462 Weighted average shares of common stock outstanding - diluted 111,367,452 77,511,677 66,492,589 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (6.11 ) $ 0.58 Diluted $ (0.93 ) $ (6.11 ) $ 0.55 Shares of common stock excluded from denominator as anti-dilutive: Unvested restricted shares 438,948 177,663 34,058 Unvested PBUs 487,995 17,589 — Total 926,943 195,252 34,058

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	13. Commitments and Contingencies Contractual Obligations The Company leases its office facilities and certain office equipment under non-cancelable operating lease agreements with various termination dates, the latest of which is April 2022. For the years ended December 31, 2016, 2015 and 2014, office lease expense totaled approximately $524,000, $687,000 and $649,000, respectively. As of December 31, 2016, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: 2017 $ 447 2018 733 2019 617 2020 620 2021 and thereafter 834 $ 3,251 Litigation Torchlight Energy Resources, Inc., Torchlight Energy, Inc. v. Husky Ventures, Inc., et al., (Cause No. 429-01961-2016) 429th Judicial District Court in Collin County, Texas. Torchlight Energy Resources, Inc. and Torchlight Energy, Inc. (collectively “Torchlight”) brought a lawsuit against the Company, two of its executive officers, its chairman of the board of directors and a former director of the Company on May 3, 2016 in Collin County, Texas (the “Torchlight Lawsuit”). The Torchlight Lawsuit arises primarily out of Torchlight’s business dealings with Husky in Oklahoma. Husky and several of its employees and affiliates are also defendants in the Torchlight Lawsuit. As part of settlement negotiations between Husky and the Company in a separate lawsuit, Husky informed the Company that it had agreed to repurchase assets from Torchlight that Husky had previously sold to Torchlight (the “Torchlight Assets”). Husky offered to sell those Torchlight Assets to the Company. In the purchase and sale agreement between Torchlight and Husky, Torchlight expressly acknowledged that the Torchlight Assets were to be sold to the Company and released the Company from any claims arising out of the sale of the Torchlight Assets. Despite this release, Torchlight has alleged multiple causes of action against the Company and its officers and directors arising out of the sale of the Torchlight Assets and Torchlight’s other business dealings it had with Husky. The Company has filed a counterclaim against Torchlight for breach of the release in the purchase and sale agreement. Torchlight has dropped their claims, without prejudice, against the former director of the Company, but continues to assert claims against the remaining Gastar defendants. The Company believes the plaintiffs’ claims are without merit and are merely an attempt to induce the Company into settling disputes that are primarily between Torchlight and Husky. The Company intends to defend this case vigorously. 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 was $20.0 million. On August 10, 2016, Gastar and the insurers settled their coverage dispute for $10.1 million. Insurers’ settlement payments to Gastar were paid in September 2016 and were recorded as litigation settlement benefit in the statement of operations for the year ended December 31, 2016. Gastar Exploration Inc. v. Christopher McArthur (Cause No.: 2015-77605) 157th Judicial District Court, Harris County, Texas . On December 29, 2015, Gastar filed suit against Christopher McArthur (“McArthur”) in the District Court of Harris County, Texas. The lawsuit arises from a demand letter sent by McArthur to Gastar in which he claimed to be party to an agreement or contract with Gastar that entitled him to be paid $2.75 million for services rendered. In August 2016, McArthur filed an amended answer admitting he had no agreement with the Company. As a result, Gastar believes McArthur’s claim has been effectively resolved. Gastar has continued to pursue a counterclaim in this action against McArthur for tortious interference with an existing contract. McArthur has filed a general denial. Gastar Exploration USA, Inc., et al v. Williams Ohio Valley Midstream LLC (American Arbitration Association Matter No. 70-198-Y-00461-13) . On July 16, 2013, Gastar USA and two similarly situated co-claimants initiated an arbitration proceeding against Williams Ohio Valley Midstream LLC (“Williams OVM”). The claimants allege that Williams OVM has breached various agreements relating to the gathering, processing and marketing of natural gas, NGLs and condensate produced from properties that are owned in part by Gastar USA in the Marcellus Shale in Marshall and Wetzel Counties, West Virginia, and requested that an Arbitration Panel assess an unspecified amount of damages against Williams OVM for, among other claims, failure to timely construct certain gathering and processing facilities and maximize the net value of the condensate and NGLs produced as provided in the agreements. On August 7, 2013, Williams OVM filed an answering statement and counterclaim for damages in excess of $612,000 in the arbitration matter. On December 31, 2013, the parties informed the Arbitration Panel that they had reached an agreement in principle to settle their disputes. The disputes were subsequently settled, on a confidential basis, between both parties on June 17, 2014. Although there were some changes to the contracts, there were no changes to existing contractual fees. After production taxes and lease operating expense reimbursement benefit, the net arbitration settlement amount received by Gastar USA was approximately $8.6 million. The Company has been expensing legal defense costs on these proceedings as they are incurred. The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Commitments Gas Purchase Agreement During December 2010, the Company, along with Atinum, entered into a gas purchase agreement with SEI Energy, LLC (“SEI”) with respect to its Marshall County, West Virginia production. The initial term of the gas purchase agreement was five years with the option to extend the term of the gas purchase agreement for an additional five year period. The Company’s Marshall County, West Virginia production was dedicated to SEI for the term of the gas purchase agreement. During June 2014, the Company entered into an agreement to include the dedication of all of its Wetzel County, West Virginia production to SEI in addition to its Marshall County, West Virginia production. Under such agreement, SEI would purchase all hydrocarbon production, including all natural gas, condensate and natural gas liquids. Upon closing of the Appalachian Basin Sale, the Company has no further obligations under the SEI agreement. SEI filed for Chapter 7 bankruptcy on June 3, 2016. As such, the Company determined that a receivable account from SEI would no longer be collectible. Drilling Program Upon completion of a Drilling Program tranche, the Investor has the right, but not the obligation, for a period of six months to cause the Company to purchase the Investor’s WI Tail interest in the Drilling Program that is not subject to final reversion for such tranche for fair market value by applying the methodology to determine a 15% discounted present value as defined by the Development Agreement. If the Investor fails to exercise the Investor Put Right within the six-month period after achieving final reversion, then for a period of six months thereafter, the Company shall have the right, but not the obligation, to purchase the WI Tail from the Investor on the same fair market value approach of the Investor Put Right. If final reversion has not been achieved by the eighth anniversary of the spud date of the first well in a given tranche, Investor will, for a period of six months thereafter, have the right to cause us to by Investor’s then-current interest in such tranche at an agreed upon valuation. Restoration, Removal and Environmental Liabilities The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year. At December 31, 2016, the Company had total liabilities of $5.5 million related to asset retirement obligations of which $89,000 is recorded as short-term liabilities and $5.4 million is recorded as long-term liabilities. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 5, “Asset Retirement Obligation.” Indemnifications Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if any, is difficult to predict. Employment Agreements The Company entered into employment agreements with its Chief Executive Officer and its Chief Financial Officer, effective February 24, 2005 (as amended July 25, 2008 and February 3, 2011) and May 17, 2005 (as amended July 25, 2008 and April 10, 2012), respectively. The agreements set forth, among other things, annual compensation, and adjustments thereto, bonus payments, fringe benefits, termination and severance provisions. The Company also has entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to indemnify them to the fullest extent permitted by law against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to the beneficiary of such indemnification agreements.

Concentration of Risk and Signi

Concentration of Risk and Significant Customers	12 Months Ended
	Dec. 31, 2016
Risks And Uncertainties [Abstract]
Concentration of Risk and Significant Customers	14. Concentration of Risk and Significant Customers The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated: For the Years Ended December 31, 2016 2015 2014 Appalachian Basin 5 % 17 % 39 % Mid-Continent 95 % 83 % 61 % The following table provides information regarding the Company’s significant customers whom accounted for more than 10% of the Company’s oil, condensate, natural gas and NGLs revenues, excluding hedge impact, for the periods indicated: For the Years Ended December 31, 2016 2015 2014 Sunoco 67 % 62 % 37 % Superior 12 % 6 % 5 % SEI (1) 5 % 22 % 50 % (1) SEI filed for Chapter 7 bankruptcy on June 3, 2016. Sunoco Logistics Partners L.P. (“Sunoco”) purchases the majority of the Company’s Mid-Continent oil production. Superior Pipeline Company (“Superior”) purchases the majority of the Company’s Mid-Continent natural gas and NGLs production. There are numerous purchase and transportation alternatives currently available in the Mid-Continent so in the event that Sunoco were to cease purchasing and transporting our oil and condensate production and/or Superior were to cease purchasing and transporting our natural gas and NGLs production, the Company’s ability to conduct normal operations would not be significantly restricted. Prior to the Appalachian Basin Sale, SEI purchased the majority of the Company’s Appalachian Basin production.

Statement of Cash Flows _ Suppl

Statement of Cash Flows – Supplemental Information	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Statement of Cash Flows - Supplemental Information	15. Statement of Cash Flows – Supplemental Information The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements: For the Years Ended December 31, 2016 2015 2014 (in thousands) Cash paid for interest, net of capitalized amounts $ 30,480 $ 26,859 $ 24,632 Non-cash transactions: Capital expenditures (excluded from) included in accounts payable and accrued drilling costs $ (82 ) $ (26,228 ) $ 12,777 Capital expenditures included in accounts receivable 409 — 4,077 Asset retirement obligation included in oil and natural gas properties 432 526 221 Asset retirement obligation for property disposals (1,045 ) (416 ) (645 ) Application of advances to operators (347 ) 11,445 58,326 Other — 5 (11 )

Quarterly Consolidated Financia

Quarterly Consolidated Financial Data - Unaudited	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Consolidated Financial Data - Unaudited	16. Quarterly Consolidated Financial Data – Unaudited The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2016 and 2015: 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 14,811 $ 12,153 $ 13,003 $ 18,287 (Loss) income from operations (1) (60,592 ) (5,142 ) 7,959 3,929 Loss before provision for income taxes (69,857 ) (14,481 ) (178 ) (4,545 ) Net loss (69,857 ) (14,481 ) (178 ) (4,545 ) Dividends on preferred stock 3,618 3,619 3,618 3,618 Net loss attributable to common stockholders (73,475 ) (18,100 ) (3,796 ) (8,163 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Diluted $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Weighted average shares of common stock outstanding: Basic 78,788,133 104,009,337 129,301,817 132,936,419 Diluted 78,788,133 104,009,337 129,301,817 132,936,419 (1) 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 34,372 $ 21,928 $ 28,386 $ 22,608 Income (loss) from operations (1) 8,172 (107,462 ) (180,272 ) (149,272 ) Income (loss) before provision for income taxes 614 (114,395 ) (188,201 ) (157,525 ) Net income (loss) 614 (114,395 ) (188,201 ) (157,525 ) Dividends on preferred stock 3,618 3,619 3,618 3,618 Net loss attributable to common stockholders (3,004 ) (118,014 ) (191,819 ) (161,143 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Diluted $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Weighted average shares of common stock outstanding: Basic 77,114,826 77,611,167 77,628,120 77,685,049 Diluted 77,114,826 77,611,167 77,628,120 77,685,049 (1) Income (loss) from operations for the second, third and fourth quarters include impairment of oil and natural gas properties of $100.2 million, $182.0 million and $144.8 million, respectively.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures - Unaudited	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Supplemental Oil and Disclosures - Unaudited	17. Supplemental Oil and Gas Disclosures – Unaudited Capitalized Costs Relating to Oil and Natural Gas Producing Activities The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities in the U.S. for the periods indicated: As of December 31, 2016 2015 2014 (in thousands) Proved properties $ 1,253,061 $ 1,286,373 $ 1,124,367 Unproved properties 67,333 92,609 128,274 Total oil and natural gas properties 1,320,394 1,378,982 1,252,641 Less: Impairment of proved oil and natural gas properties (813,314 ) (764,817 ) (337,939 ) Accumulated depreciation, depletion and amortization (315,373 ) (286,020 ) (223,555 ) Net capitalized costs $ 191,707 $ 328,145 $ 691,147 Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs of approximately $1.5 million, $2.4 million and $2.4 million at December 31, 2016, 2015 and 2014, respectively. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands) Property acquisition Proved $ 570 $ 15,615 $ — Unproved 38,941 50,434 41,475 Exploration 19,761 53,290 127,384 Development 3,810 54,316 57,913 Total costs incurred $ 63,082 $ 173,655 $ 226,772 Results of Operations for Oil and Natural Gas Producing Activities The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated: For the Year Ended December 31, 2016 2015 2014 (in thousands, except per Mcfe data) Oil, condensate, natural gas and NGLs sales, including commodity derivatives $ 58,254 $ 107,294 $ 171,418 Production expenses (24,217 ) (28,792 ) (29,735 ) Impairment of oil and natural gas properties (48,497 ) (426,878 ) — Depreciation, depletion and amortization (29,353 ) (62,465 ) (45,765 ) Results of producing activities $ (43,813 ) $ (410,841 ) $ 95,918 Depreciation, depletion and amortization per MBoe $ 10.23 $ 12.67 $ 12.34 The results of producing activities exclude interest charges and general corporate expenses. In accordance with current authoritative guidance, estimates of the Company’s proved reserves and future net revenues are made using benchmark prices, before lease adjustments, that are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2016 and 2015. The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves: As of December 31, 2016 2015 Natural gas (per MMBtu): Henry Hub $ 2.48 $ 2.59 Oil (per Bbl): WTI spot $ 42.75 $ 50.28 These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas prices and oil prices, which have fluctuated significantly in recent years. Net Proved and Proved Developed Reserve Summary Reserve Estimation. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2016, 2015, and 2014. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e., prices and costs as of the date the estimate is made). Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. The Company’s proved developed and proved undeveloped reserves are located only in the U.S. The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2016, 2015 and 2014: Change in Proved Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) Proved reserves as of December 31, 2013 14,718 180,710 9,798 54,634 2014 Activity: Extensions and discoveries (4) 13,137 121,672 9,394 42,810 Revisions of previous estimates 1,780 (2,465 ) 7,205 8,574 Production (975 ) (11,598 ) (800 ) (3,708 ) Sales in place (24 ) (1,314 ) (4 ) (247 ) Proved reserves as of December 31, 2014 28,636 287,005 25,593 102,063 2015 Activity: Extensions and discoveries (5) 4,777 14,114 2,244 9,374 Revisions of previous estimates (6) (8,962 ) (182,600 ) (13,873 ) (53,268 ) Production (1,425 ) (13,759 ) (1,212 ) (4,931 ) Purchases in place 1,270 4,965 873 2,971 Sales in place (94 ) (1,274 ) (26 ) (332 ) Proved reserves as of December 31, 2015 24,202 108,451 13,599 55,877 2016 Activity: Extensions and discoveries 1,582 7,213 898 3,681 Revisions of previous estimates (7) (9,890 ) (17,825 ) (3,317 ) (16,177 ) Production (1,105 ) (6,145 ) (739 ) (2,869 ) Sales in place (1,033 ) (53,841 ) (4,929 ) (14,935 ) Proved reserves as of December 31, 2016 13,756 37,853 5,512 25,577 (1) Thousand barrels (2) Million cubic feet or million cubic feet equivalent, as applicable (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. (4) Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. (5) All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. (6) The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. (7) The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position. Proved Developed and Undeveloped Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) December 31, 2014 Proved developed reserves 6,968 114,564 10,726 36,789 Proved undeveloped reserves 21,668 172,441 14,867 65,274 Total 28,636 287,005 25,593 102,063 December 31, 2015 Proved developed reserves 7,181 77,966 8,240 28,415 Proved undeveloped reserves 17,021 30,485 5,359 27,462 Total 24,202 108,451 13,599 55,877 December 31, 2016 Proved developed reserves 6,037 22,786 3,181 13,015 Proved undeveloped reserves 7,719 15,067 2,332 12,562 Total 13,756 37,853 5,512 25,577 (1) Thousand barrels (2) Million cubic feet (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented. For the years ended December 31, 2016, 2015 and 2014 future cash inflows were computed using the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil (the “benchmark base prices”). For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations: For the Years Ended December 31, 2016 2015 2014 Natural gas, per MMBtu Henry Hub $ 2.48 $ 2.59 $ 4.35 Oil, per barrel: WTI spot $ 42.75 $ 50.28 $ 94.99 These benchmark base prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. The Company also includes its standard overhead charges pursuant to the respective property joint operating agreements in the calculation of its future cash flows. The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate could also result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or changes in regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized. A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves in the U.S. is presented below (in thousands): December 31, 2014: Future cash inflows $ 3,855,227 Future production costs (1,048,554 ) Future development costs (611,602 ) Future income taxes (486,593 ) Future net cash flows 1,708,478 10% annual discount for estimated timing of cash flows (891,739 ) Standardized measure of discounted future cash flows $ 816,739 December 31, 2015: Future cash inflows $ 1,425,734 Future production costs (547,484 ) Future development costs (365,123 ) Future income taxes (1) — Future net cash flows 513,127 10% annual discount for estimated timing of cash flows (283,324 ) Standardized measure of discounted future cash flows $ 229,803 December 31, 2016: Future cash inflows $ 710,370 Future production costs (328,010 ) Future development costs (123,214 ) Future income taxes (1) — Future net cash flows 259,146 10% annual discount for estimated timing of cash flows (117,815 ) Standardized measure of discounted future cash flows $ 141,331 (1) No future taxes payable has been included in the determination of discounted future net cash flows for 2015 and 2016 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows. Changes in Standardized Measure of Discounted Future Net Cash Flows The principal sources of changes in the standardized measure of future net cash flows are as follows (in thousands): December 31, 2013 $ 515,829 Extensions and discoveries, less related costs 369,806 Sale of natural gas and oil, net of production costs (122,114 ) Sales of reserves in place (1,475 ) Revisions of previous quantity estimates 101,044 Net change in income tax (95,245 ) Net change in prices and production costs 59,786 Accretion of discount (3,996 ) Development costs incurred 37,461 Net change in estimated future development costs (1,276 ) Change in production rates (timing) and other (43,081 ) December 31, 2014 $ 816,739 Extensions and discoveries, less related costs 71,547 Sale of natural gas and oil, net of production costs (53,914 ) Purchases of reserves in place 9,937 Sales of reserves in place (4,853 ) Revisions of previous quantity estimates (324,036 ) Net change in income tax 171,946 Net change in prices and production costs (604,074 ) Accretion of discount 98,869 Development costs incurred 10,500 Net change in estimated future development costs 31,131 Change in production rates (timing) and other 6,011 December 31, 2015 $ 229,803 Extensions and discoveries, less related costs 19,270 Sale of natural gas and oil, net of production costs (36,900 ) Sales of reserves in place (16,023 ) Revisions of previous quantity estimates (115,785 ) Net change in income tax — Net change in prices and production costs (43,270 ) Accretion of discount (16,461 ) Net change in estimated future development costs 119,531 Change in production rates (timing) and other 1,166 December 31, 2016 $ 141,331

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the U.S.(“GAAP”). The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 17. “Supplemental Oil and Gas Disclosures.” 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).
Subsequent Events	Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate. Preferred Dividends On January 10, 2017, the Company, together with the parties thereto, entered into Amendment No. 10 to the Second Amended and Restated Credit Agreement (“Amendment No. 10”), dated as of January 10, 2017. Amendment No. 10, among other things, permitted the limited payment of certain cash dividends on the Company’s preferred stock, including the dividends declared payable on January 31, 2017, provided that (1) the Company’s borrowing base will be correspondingly reduced in the amount of any such dividend payment and (2) the Company pays down its outstanding indebtedness under the Revolving Credit Facility in the amount of any resulting borrowing base deficiency. Under Amendment No. 10, payment of the declared January 2017 dividend and monthly preferred stock cash dividends through May 2017 was permitted contingent upon the satisfaction of certain conditions, including but not limited to, (1) the absence of any defaults or borrowing base deficiency, (2) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (3) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the Company’s at-the-market sales program). The Company paid all accumulated and unpaid dividends for the period April 2016 to December 2016, as well as the January 2017, preferred dividend payment on January 31, 2017. Under the agreement pursuant to which the Term Loan is issued and the indenture governing the Notes, cash dividend payments on the Company’s outstanding preferred stock are permitted through July 31, 2018 contingent upon the absence of any defaults. From and after August 1, 2018, dividend payments on the Series A and Series B Preferred Stock are permitted subject to the Company’s compliance with a certain fixed charge coverage ratio test. Stockholder Rights Agreement On January 27, 2017, the Company’s board of directors adopted a replacement stockholder rights plan (the “2017 Rights Agreement”) to effectively replace the stockholders rights plan adopted on January 18, 2016 (the “2016 Rights Agreement”). As of January 18, 2017, the 2016 Rights Agreement expired pursuant to its terms. Pursuant to the 2017 Rights Agreement, the Company’s board of directors declared a non-taxable dividend of one preferred share purchase right (each, a “Right”) for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on February 10, 2017. Each Right entitles the registered holder, subject to the terms of the 2017 Rights Agreement to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $10.74, subject to certain adjustments. The purpose of the 2017 Rights Agreement is to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. Ares Investment Transaction On March 3, 2017 (the “Closing Date”), the Company closed the previously announced capital and refinancing transactions (the “Ares Investment Transaction”) with certain funds (the “Purchasers”) affiliated with Ares Management, L.P. (“Ares”). Securities Purchase Agreement On February 16, 2017, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with the Purchasers, pursuant to which the Company issued and sold for cash to the Purchasers (i) $125.0 million aggregate principal amount of its Convertible Notes due 2022 (the “Notes”), which Notes, subject to the receipt of approval of the Company’s stockholders, will be convertible into common stock, par value $0.001 per share of the Company (the “Common Stock”) or, in certain circumstances, cash in lieu of Common Stock or a combination of cash and shares of Common Stock as described below and (ii) 29,408,305 shares of Common Stock for a purchase price of $50.0 million. In addition, an affiliate of Ares concurrently loaned the Company $250.0 million pursuant to a senior secured first-lien term loan as further described below (the “Term Loan”). The proceeds from the sale of the Notes, the Common Stock and the Term Loan were used to fully repay the $69.2 million outstanding on the Company’s revolving credit facility and to satisfy and discharge its $325.0 million of 8.625% senior secured notes due May 2018, which will be redeemed at a price of 102.156% of their principal amount on March 24, 2017, and to pay the expenses from the Ares Investment Transaction. The issuance of Common Stock and the Notes were consummated as a private placement to “accredited investors” (as that term is defined under Rule 501 of Regulation D), exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), in reliance upon Section 4(a)(2) of the Securities Act and Regulation D Rule 506, as a transaction by an issuer not involving a public offering. The issuance of the shares of Common Stock to the Purchasers was priced based on a 30-trading day volume weighted average trading price (the “VWAP”) of $1.7002 per share, determined as of February 15, 2017, the date immediately prior to the signing date of the Purchase Agreement. This resulted in the issuance of 29,408,305 shares of Common Stock to the Purchasers, or approximately 18.8% of the shares of the Company’s 156,715,833 shares of Common Stock issued and outstanding as of January 31, 2017. For so long as the Purchasers, collectively, beneficially own 10% or more of the Common Stock (including for this purpose all shares of Common Stock issuable upon conversion of the Notes), the Purchasers will have certain preemptive rights to purchase their pro rata share of any additional equity securities offered by the Company in the future on similar terms as are offered to other purchasers. On March 2, 2017, the Company entered into Amendment No. 1 to the Purchase Agreement (the “Amendment”) with the Purchasers. The Amendment amended the director nomination rights described below and the requisite ownership thresholds to exclude holders of any warrants or other convertible securities to satisfy the applicable NYSE MKT rules and regulations. Pursuant to the Purchase Agreement, as amended by the Amendment, and so long as the Purchasers beneficially own (excluding ownership of Voting Stock (as defined in the Purchase Agreement) that such person only has the right to acquire) at least 15% of the total outstanding voting power of the Company’s Voting Stock, the Purchasers will be entitled to nominate two directors to an expanded eight-member board of directors of the Company. If the Purchasers beneficially own (excluding ownership of Voting Stock that such person only has the right to acquire) 5% or more, but less than 15%, of the total outstanding voting power of the Company’s Voting Stock, the Purchasers will be entitled to nominate one director to the board of directors of the Company. Term Loan On the Closing Date, the Company entered into the Third Amended and Restated Credit Agreement among the Company, as borrower, the guarantor party thereto, AF V Energy I Holdings, L.P., an affiliate of Ares, as initial lender, and Wilmington Trust, National Association, as administrative agent. The loans made pursuant to the Term Loan bear interest a per annum rate equal to 8.5%, payable on a quarterly basis on each March 1, June 1, September 1 and December 1 of each year, commencing on June 1, 2017. The Term Loan has a scheduled maturity of March 3, 2022. In addition, the Term Loan is subject to an interest “make-whole” and repayment premium, such that any repayment or prepayment of the loans thereunder prior to the stated maturity date shall be subject to the payment of a repayment premium, and depending on the date of such repayment or prepayment, the applicable interest “make-whole” amount, with the amount of such repayment premium decreasing over the life of the Term Loan. The Term Loan is guaranteed by the Company’s domestic subsidiary (excluding certain insignificant subsidiaries) and will be guaranteed by all of the Company’s future domestic subsidiaries formed during the term of the Term Loan. The Term Loan is secured by a first-priority lien on substantially all of the assets of the Company as its subsidiary, excluding certain assets as customary exceptions. The Term Loan contains various customary covenants for credit facilities of this type, including, among others, restrictions on granting liens, incurrence of other indebtedness, payments of certain dividends and other restricted payments, engaging in transactions with affiliates, dispositions of assets and other covenants, in each case subject to certain baskets and exceptions. All outstanding amounts owed under the Term Loan become due and payable upon the occurrence of certain usual and customary events of default, including among others: (i) failure to make payments; (ii) non-performance of covenants and obligations continuing beyond any applicable grace period; and (iii) the occurrence of a change in control of the Company, as defined in the Term Loan. The Company does not expect that the covenants or other provisions of the Term Loan or the Notes will restrict the payment of dividends on the Company’s outstanding preferred stock through July 2018, and, thereafter, such payments will be subject to satisfaction of certain financial conditions. Any future dividends on such preferred stock, however, remain subject to declaration by the Company, and there is no assurance that the Company will declare and pay any future dividends, even if it is permitted to do so under the terms of the Term Loan or the Notes. Indenture and Notes On the Closing Date, the Company entered into an indenture (the “Indenture”) by and among the Company, the subsidiary guarantor named therein, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral trustee, with respect to the Notes. The principal terms of the Notes are governed by the Indenture. Pursuant to the Indenture, the Notes were issued for cash at par, bear interest initially at 6.0% per annum and will mature on March 1, 2022, unless earlier repurchased, redeemed or converted in accordance with the terms of the Indenture. Interest is payable on the Notes on each March 1, June 1, September 1 and December 1 of each year, commencing on June 1, 2017. Subject to receipt of stockholder approval on or before July 3, 2017 of the issuance of Common Stock upon conversion of the above Notes (the “Requisite Stockholder Approval”), the Notes will be convertible at the option of the holder into shares of Common Stock based on an initial conversion rate of 452.4355 shares of Common Stock per $1,000 principal amount of the Notes (which is equivalent to an initial conversion price of approximately $2.21 per share, or 30% above the VWAP per share of Common Stock for the 30 trading days prior to execution of the Purchase Agreement), subject to certain adjustments and the issuance of additional “make-whole” shares under circumstances specified in the Indenture. Subject to certain limitations, the Company will have the right to settle its conversion obligations on the Notes in cash, shares of Common Stock or a combination of cash and shares of Common Stock. If the Company obtains the Requisite Stockholder Approval, then the Company will have the right to redeem the Notes (i) on or after March 3, 2019, if the last reported sale price per share of Common Stock exceeds 150% of the conversion price for periods specified in the Indenture; and (ii) on or after March 1, 2021 without regard to such condition, in each case at cash redemption price equal to the principal amount of the Notes to be redeemed plus accrued interest, if any. The interest rate, conversion rate and other financial terms of the Notes were determined by negotiations between the Company and the Purchasers. The interest rate on the Notes will be subject to an increase in certain circumstances if the Company fails to obtain Requisite Stockholder Approval or to comply with certain obligations under the Registration Rights Agreement (as defined below), or in the case of certain issuances of Common Stock at below $1.7002 per share (subject to adjustment). The Notes will be secured by a second-priority lien on substantially all of the assets of the Company. The Indenture restricts the ability of the Company and certain of its subsidiaries to, among other things: (i) pay dividends or make other distributions in respect of the Company’s capital stock or make other restricted payments; (ii) incur additional indebtedness and issue preferred stock; (iii) make certain dispositions and transfers of assets; (iv) engage in transactions with affiliates; (v) create liens; (vi) engage in certain business activities that are not related to oil and gas; and (vii) impair any security interest. These covenants are subject to a number of exceptions and qualifications. The Indenture provides that a number of events will constitute an Event of Default (as defined in the Indenture), including, among other things: (i) a failure to pay the Notes when due at maturity, upon redemption or repurchase; (ii) failure to pay interest for 30 days; (iii) the Company’s failure to deliver certain notices; (iv) a default in the Company’s obligation to convert the Notes; (v) the Company’s failure to comply with certain covenants relating to merger, consolidation or sale of assets; (vi) the Company’s failure to comply, for 60 days following notice, with any of the other covenants or agreements in the Indenture; (vii) a default, which is not cured within 30 days, by the Company or any Restricted Subsidiaries (as defined in the Indenture) with respect to any mortgages or any indebtedness for money borrowed of at least $15 million; (viii) one or more final judgments against the Company or any of its Restricted Subsidiaries for the payment of at least $15 million; (ix) the Company’s failure to make any payments required under that certain development agreement; (x) causing any Guarantee (as defined in the Indenture) to cease to be in full force and effect; (xi) the cessation to be in full force and effect of any of the collateral agreements related to the Ares Investment Transaction; and (xii) certain events of bankruptcy or insolvency. In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to the Company, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. If Requisite Stockholder Approval is not obtained, then upon any acceleration of the Notes following an Event of Default, holders will be entitled to receive a “make-whole” premium in addition to principal and accrued interest. If stockholders do not approve the conversion rights of the Notes into Common Stock within four months of the Closing Date, the Notes will not be convertible and the interest rate on the Notes will increase in increments to 15% per annum, and will not be redeemable by the Company prior to maturity except upon payment of a “make-whole” redemption premium. If at least a majority of the Notes issued pursuant to the Purchase Agreement cease to be held by affiliates of Ares after receipt of Requisite Stockholder Approval as provided in the Indenture, the liens securing the Notes will be released and substantially all of the restrictive covenants in the Indenture will terminate. Registration Rights Agreement On the Closing Date, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Purchasers, pursuant to which the Company has agreed that the future resale of the Common Stock sold in the Ares Investment Transaction and the shares of Common Stock issued upon conversion of the Notes will be registered under the Securities Act. The Registration Rights Agreement includes a plan of distribution permitting the Purchasers to sell the covered Common Stock by various means, including in open market sales from time to time, pursuant to underwritten offerings or in negotiated sales. The failure to (i) file a registration statement prior to July 3, 2017, (ii) have the registration statement declared effective within four months of the filing date for the Company’s 2016 Annual Report on From 10-K or (iii) thereafter, with certain exceptions, maintain the effectiveness of the registration statement, will result in additional interest accruing on the Notes for so long as they are outstanding. The Company will be required to cooperate in a maximum of four underwritten offerings under the Registration Rights Agreement at the expense of the Company (other than underwriting discounts). Intercreditor Agreement On the Closing Date, Wilmington Trust, National Association, as administrative agent for the priority lien secured parties, and Wilmington Trust, National Association, as the second lien agent for the second lien secured parties, entered into an intercreditor agreement, which was acknowledged and agreed to by the Company and its subsidiary guarantor (the “Intercreditor Agreement”) to govern the relationship of the lenders under the Term Loan and the holders of any other priority lien obligations on the one hand, and the noteholders and holders of any other second lien obligations that the Company may issue in the future, with respect to the sharing of collateral, the priority of the liens thereon and certain other matters. Swap Intercreditor Agreement On the Closing Date, Morgan Stanley Capital Group, Inc., NextEra Energy Marketing, LLC, Cargill, Incorporated, Koch Supply & Trading, LP, (collectively, the “Swap Counterparties”), the Company, the guarantor party thereto, Wilmington Trust, National Association, as administrative agent for the lenders from time to time party to the Term Loan, and Wilmington Trust, National Association, as collateral agent on behalf of the secured parties (the “Collateral Agent”) entered into an intercreditor agreement (the “Swap Intercreditor Agreement”) pursuant to which the Collateral Agent will receive, hold, administer, maintain, enforce and distribute the proceeds of all of the loan obligations, swap obligations and its liens upon the collateral for the benefit of the current and future lenders under the Term Loan and the Swap Counterparties.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation.
Use of estimates in Preparation of Financial Statements	Use of estimates in Preparation of Financial Statements The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company's cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $71.5 million and $50.1 million as of December 31, 2016 and 2015, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.
Accounts Receivable	Accounts Receivable Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible. During 2016, the Company determined that a receivable account from a third-party natural gas and NGLs purchaser would no longer be collectible as a result of the third-party purchaser filing for bankruptcy. A summary of the activity related to the allowance for doubtful accounts is as follows: For the years ended December 31, 2016 2015 2014 (in thousands) Allowance for doubtful accounts, beginning of year $ — $ — $ 507 Expense 1,953 — — Reductions/write-offs — — (507 ) Allowance for doubtful accounts, end of year $ 1,953 $ — $ —
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company's only cost center. Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations. In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization. The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2016 and 2015 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered. The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted.
Asset Retirement Obligation	Asset Retirement Obligation Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations.
Furniture and Equipment	Furniture and Equipment Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years.
Capitalized Interest	Capitalized Interest The Company capitalizes interest on assets not being amortized related to specific projects such as its drilling in progress and unproven oil and natural gas property expenditures. The methodology for capitalizing interest on general funds begins with a determination of the borrowings applicable to the qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off debt. The Notes and Revolving Credit Facility were included in the rate calculation of capitalized interest incurred for the year-ended December 31, 2016. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $3.1 million, $3.9 million and $4.3 million for 2016, 2015 and 2014, respectively.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value.
Deferred Financing Costs	Deferred Financing Costs Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense. Deferred financing costs are presented as a direct reduction to the carrying amount of the related debt liability where the debt liability is not a line-of-credit arrangement. The following table indicates deferred charges and related accumulated amortization as of the dates indicated: As of December 31, 2016 2015 Deferred charges $ 2,971 $ 1,686 Accumulated amortization (2,295 ) (701 ) Deferred charges, net $ 676 $ 985
Derivative Instruments and Hedging Activity	Derivative Instruments and Hedging Activity The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.” The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in gain (loss) on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in gain (loss) on commodity derivatives contracts in the Company’s consolidated statement of operations.
Stock-Based Compensation	Stock-Based Compensation The Company reports compensation expense for restricted common stock and performance based units (“PBUs”) granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. Stock-based compensation cost for restricted shares is estimated at the grant date based on the award’s fair value, which is equal to the prior day’s closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant based on the award’s fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. Forfeitures of unvested stock options and restricted common shares historically were calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. Beginning in 2017, the Company will no longer apply a forfeiture rate at grant and will account for forfeitures as they occur. For 2016, 2015 and 2014, the Company used forfeiture rates in determining compensation expense of 19.1%, 17.5% and 25.5%, respectively.
Treasury Stock	Treasury Stock Treasury stock purchases are recorded at cost as a reduction to common stock. Shares of common stock are canceled upon repurchase.
Revenue Recognition	Revenue Recognition The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company’s NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company’s wet gas production. The Company’s reported production volumes reflect incremental post-processing NGLs volumes and residual gas volumes with which the Company is credited under its sales contracts. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2016, 2015 and 2014. The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. In addition, oil, condensate, natural gas and NGLs volumes sold are not significantly different from the Company’s share of production. The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet.
Deferred Income Taxes	Deferred Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.
Comprehensive Income	Comprehensive Income Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Company has no items of comprehensive income other than net income in any period presented. Therefore, net income attributable to common stockholders as presented in the consolidated statements of operations equals comprehensive income.
Earnings or Loss per Share	Earnings or Loss per Share Basic earnings or loss per share is computed by dividing net income (loss) available to common stockholders, net of accumulated paid and unpaid dividends, by the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed by dividing net income (loss) available to common stockholders, net of accumulated and unpaid dividends, by the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of unvested restricted shares and PBUs.
Co-participation Operations	Co-participation Operations The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Industry Segment and Geographic Information	Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long-lived assets located outside the U.S.
Foreign Currency Exchange	Foreign Currency Exchange The consolidated financial statements of the Company are presented in U.S. dollars. The functional currency for the Company is U.S. dollars. Transactions in currencies other than the functional currency are recorded using the appropriate exchange rate at the time of the transaction. All of the Company’s operations are conducted in U.S. dollars. The Company owns immaterial non-operating working interests in two natural gas wells located in Alberta, Canada, from which it has received no revenue since January 1, 2012. Canadian records are maintained in the local currency and re-measured to the functional currency as follows: monetary assets and liabilities are converted using the balance sheet period-end date exchange rate, while the non-monetary assets and liabilities are converted using the historical exchange rate. Expenses and income items are converted using the weighted average exchange rates for the reporting period. Foreign transaction gains and losses are reported on the consolidated statement of operations.
Recent Accounting Developments	Recent Accounting Developments The following recently issued accounting pronouncements have been adopted or may impact us in future periods: Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued updated guidance to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this update (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments in this update affect all reporting entities that must determine whether they have acquired or sold a business and are effective for public business entities for annual reporting periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after the effective date and no disclosures are required at transition. Early application is allowed as follows (1) for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance and (2) for transactions in which a subsidiary is deconsolidated or a group of assets is derecognized that occur before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. Due to its application to future acquisitions and disposals, the adoption of this guidance, effective January 1, 2018, will not have any immediate effect on our financial position or results of operations. Statement of Cash Flows. In August 2016, the FASB issued updated guidance associated with the classification of certain cash receipts and cash payments on the statement of cash flows. The amended guidance addresses specific cash flow issues with the objective of reducing existing diversity in practice. The amendment provides guidance on the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments in this update apply to all entities required to present a statement of cash flows. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company is currently evaluating the effect that adopting this guidance will have on its presentation of cash flows. The Company does not believe the effects of adopting this updated guidance will have a material effect on its statement of cash flows and it is expected to have no effect on the Company’s financial position or results of operations. Compensation – Stock Compensation. In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company has adopted this updated guidance for the fiscal year beginning January 1, 2017 and will record an adjustment of approximately $657,000 to retained earnings on a modified retrospective basis to properly reflect the adjustment to stock compensation expense to reduce the forfeiture rate to 0%. Leases. In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has begun analyzing its lease contracts but has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Income Taxes. In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards (IFRS). IAS 1, . This guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period and can be applied either prospectively or retrospectively to all periods presented. The Company does not expect the adoption of this guidance to materially impact its consolidated financial statements. Going Concern. Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue, which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, “Revenue Recognition,” and most industry-specific guidance. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018 and such proposal was subsequently adopted by the FASB in August 2015. The Company is currently determining the impacts of the new revenue recognition standard on its contracts. The Company’s approach includes evaluating its key revenue contracts representative of its revenue and comparing historical accounting policies and practices to the new standard. The Company’s revenue contracts are primarily normal purchase/normal sale contracts with index pricing that settle monthly and as such, the Company does not expect that the new revenue recognition standard will have a material impact on its financial statements upon adoption. The Company intends to apply the new standard utilizing a modified retrospective basis that could result in a cumulative effect adjustment as of January 1, 2018.

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of the activity related to the allowance for doubtful accounts	A summary of the activity related to the allowance for doubtful accounts is as follows: For the years ended December 31, 2016 2015 2014 (in thousands) Allowance for doubtful accounts, beginning of year $ — $ — $ 507 Expense 1,953 — — Reductions/write-offs — — (507 ) Allowance for doubtful accounts, end of year $ 1,953 $ — $ —
Schedule of deferred charges and accumulated amortization	The following table indicates deferred charges and related accumulated amortization as of the dates indicated: As of December 31, 2016 2015 Deferred charges $ 2,971 $ 1,686 Accumulated amortization (2,295 ) (701 ) Deferred charges, net $ 676 $ 985

Property, Plant And Equipment (

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Business Acquisition [Line Items]
Property, Plant and Equipment	The Company’s total property, plant and equipment consists of the following: December 31, 2016 2015 (in thousands) Oil and natural gas properties, full cost method of accounting: Unproved properties $ 67,333 $ 92,609 Proved properties 1,253,061 1,286,373 Total oil and natural gas properties 1,320,394 1,378,982 Furniture and equipment 2,622 3,068 Total property and equipment 1,323,016 1,382,050 Impairment of proved natural gas and oil properties (813,314 ) (764,817 ) Accumulated depreciation, depletion and amortization (317,698 ) (288,299 ) Total accumulated depreciation, depletion and amortization (1,131,012 ) (1,053,116 ) Total property and equipment, net $ 192,004 $ 328,934
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	The following table summarizes the components of unproved properties excluded from amortization for the periods indicated: December 31, 2016 2015 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 1,100 $ 1,533 Acreage acquisition costs 58,857 82,560 Capitalized interest 7,376 8,516 Total unproved properties excluded from amortization $ 67,333 $ 92,609
Schedule Of Relevant Assumptions Used In Ceiling Test Computations	The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials: 2016 Total December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.48 $ 2.28 $ 2.24 $ 2.40 West Texas Intermediate oil price (per Bbl) (1) $ 42.75 $ 41.68 $ 43.12 $ 46.26 Impairment recorded (pre-tax) (in thousands) $ 48,497 $ — $ — $ — $ 48,497 2015 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.59 $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 50.28 $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 426,878 $ 144,760 $ 181,966 $ 100,152 $ — 2014 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 4.35 $ 4.24 $ 4.10 $ 3.99 West Texas Intermediate oil price (per Bbl) (1) $ 94.99 $ 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.
Husky Acquisition
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	The following unaudited pro forma results for the year ended December 31, 2015 shows the effect on the Company’s consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) additional depreciation, depletion and amortization expense as a result of the Company’s increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Year Ended December 31, 2015 (in thousands, except (Unaudited) Revenues $ 115,147 Net loss $ (470,874 ) Loss per share: Basic $ (6.07 ) Diluted $ (6.07 )
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Husky Acquisition (in thousands): Consideration: Cash consideration $ 42,085 Conveyance of undeveloped acreage — Total purchase price $ 42,085 Estimated Fair Value of Assets Acquired: Unproved properties $ 27,875 Proved properties 15,592 Other (1,382 ) Total assets acquired $ 42,085
Appalachian Basin
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	The following unaudited pro forma results for the years ended December 31, 2016 and 2015 show the effect on the Company’s consolidated results of operations as if the Appalachian Basin Sale had occurred at the beginning of the periods presented. The pro forma results are the result of excluding from the statement of operations of the Company the revenues and direct operating expenses for the properties divested adjusted for (1) the reduction in ARO liabilities and accretion expense for the properties divested, (2) the reduction in depreciation, depletion and amortization expense as a result of the divestiture and (3) the reduction in interest expense as a result of the pay down of debt under the Revolving Credit Facility in conjunction with the closing of the Appalachian Basin Sale. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Years Ended December 31, 2016 2015 (in thousands, except (Unaudited) Revenues $ 55,177 $ 93,783 Net loss $ (98,459 ) $ (464,788 ) Loss per share: Basic $ (0.88 ) $ (6.00 ) Diluted $ (0.88 ) $ (6.00 )

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Summary of Notes Balance	A summary of the Notes balance for the periods indicated is as follows: December 31, 2016 2015 (in thousands) Notes, principal balance $ 325,000 $ 325,000 Less: Unamortized discounts (4,342 ) (7,151 ) Deferred financing costs (795 ) (1,373 ) Notes, net $ 319,863 $ 316,476

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	A summary of the activity related to the asset retirement obligation is as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Asset retirement obligation, beginning of year $ 6,086 $ 5,557 $ 6,063 Liabilities incurred during period 196 302 305 Liabilities settled during period (90 ) (37 ) (704 ) Accretion expense 368 502 506 Revision in previous estimates and other 17 178 32 Deletions related to property disposals (1,045 ) (416 ) (645 ) Asset retirement obligation, end of year $ 5,532 $ 6,086 $ 5,557

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring and Nonrecurring	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015: Fair value as of December 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 71,529 $ — $ — $ 71,529 Commodity derivative contracts — — 7,850 7,850 Liabilities: Commodity derivative contracts — — (338 ) (338 ) Total $ 71,529 $ — $ 7,512 $ 79,041 Fair value as of December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Assets: Cash and cash equivalents $ 50,074 $ — $ — $ 50,074 Commodity derivative contracts — — 24,869 24,869 Liabilities: Commodity derivative contracts — — (451 ) (451 ) Total $ 50,074 $ — $ 24,418 $ 74,492
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation	The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2016 and 2015. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2016 and 2015. For the Years Ended December 31, 2016 2015 (in thousands) Balance at beginning of period $ 24,418 $ 27,502 Total (losses) gains included in earnings (2,863 ) 24,589 Purchases 565 1,326 Issuances (165 ) (1,313 ) Settlements (1) (14,443 ) (27,686 ) Balance at end of period $ 7,512 $ 24,418 The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2016 and 2015 $ (13,622 ) $ (1,890 ) (1) Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations.

Derivative Instruments and He31

Derivative Instruments and Hedging Activity (Tables)	12 Months Ended
	Dec. 31, 2016
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: For 2016 2015 (in thousands) Current commodity derivative premium put payable $ 1,654 $ 3,194 Long-term commodity derivative premium payable 969 2,788 Total unamortized put premium liabilities $ 2,623 $ 5,982 For the Years Ended December 31, 2016 2015 (in thousands) Put premium liabilities, beginning balance $ 5,982 $ 7,183 Settlement of put premium liabilities (3,194 ) (2,295 ) Additional put premium liabilities (165 ) 1,094 Put premium liabilities, ending balance $ 2,623 $ 5,982
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 December 31, 2016: Amortization (in thousands) January to December 2017 $ 1,654 January to December 2018 969 Total unamortized put premium liabilities $ 2,623
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 commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value December 31, Balance Sheet Location 2016 2015 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 6,212 $ 15,534 Commodity derivative contracts Other assets 1,638 9,335 Commodity derivative contracts Current liabilities (338 ) — Commodity derivative contracts Long-term liabilities — (451 ) Total derivatives not designated as hedging instruments $ 7,512 $ 24,418 Amount of (Loss) Gain Recognized in Income on Derivatives For the Years Ended December 31, Location of (Loss) Gain Recognized in Income on Derivatives 2016 2015 2014 (in thousands) Derivatives Commodity derivative contracts (Loss) gain on commodity derivatives contracts $ (2,863 ) $ 24,589 $ 19,569 Total $ (2,863 ) $ 24,589 $ 19,569
Natural Gas
Derivative [Line Items]
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of December 31, 2016, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in MMBtu’s) 2017 Costless three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 2017 (1) Costless collar 2,000 180,000 $ — $ 3.10 $ — $ 3.78 2017 (2) Fixed price swap 1,500 321,000 $ 3.30 $ — $ — $ — 2018 Costless three-way collar 5,000 1,825,000 $ — $ 3.00 $ 2.35 $ 4.00 (1) For the period January to March 2017. (2) For the period April to October 2017.
Crude Oil
Derivative [Line Items]
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions	As of December 31, 2016, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume (1) Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in Bbls) 2017 Costless three-way collar 280 102,200 $ — $ 80.00 $ 65.00 $ 97.25 2017 Costless three-way collar 250 91,250 $ — $ 80.00 $ 60.00 $ 98.70 2017 (2) Protective spread 200 36,200 $ 60.00 $ — $ 42.50 $ — 2017 Put spread 500 182,500 $ — $ 82.00 $ 62.00 $ — 2017 (2) Protective spread 200 36,200 $ 57.50 $ — $ 42.50 $ — 2017 (2) Fixed price swap 300 54,300 $ 50.10 $ — $ — $ — 2017 (3) Costless three-way collar 200 36,800 $ — $ 60.00 $ 42.50 $ 85.00 2017 (3) Costless three-way collar 200 36,800 $ — $ 57.50 $ 42.50 $ 76.13 2017 (4) Fixed price swap 200 18,000 $ 50.05 $ — $ — $ — 2017 (2) Fixed price swap 275 49,775 $ 51.25 $ — $ — $ — 2018 (5) Put spread 425 103,275 $ — $ 80.00 $ 60.00 $ — (1) Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. (2) For the period January to June 2017. (3) For the period July to December 2017. (4) For the period January to March 2017. (5) For the period January to August 2018.

Capital Stock (Tables)

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2016
Stockholders Equity Note [Abstract]
Schedule of Issuances And Forfeitures Of Common Shares	The following table provides information regarding the issuances and forfeitures of the Company's common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated: For the Years Ended December 31, 2016 2015 Other stock issuances: Shares of restricted common stock granted 1,764,645 1,426,604 Shares of restricted common stock vested 1,487,269 1,422,670 Shares of common stock issued pursuant to PBUs vested, net of forfeitures of 207,891 shares and 212,858 shares, respectively 502,593 497,636 Shares of restricted common stock surrendered upon vesting/exercise (1) 392,094 413,333 Shares of restricted common stock forfeited 128,435 119,499 (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.

Equity Compensation Plans (Tabl

Equity Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable	The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2016: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at December 31, 2015 866,600 $ 11.75 Granted — — Exercised — — Canceled/Expired (571,000 ) 14.77 Forfeited (81,000 ) 8.75 Outstanding at December 31, 2016 214,600 $ 4.87 Options vested and exercisable at December 31, 2016 214,600 $ 4.87 1.98 $ —
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	The following table summarizes information related to restricted shares at December 31, 2016: Shares Weighted Average Fair Value per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding non-vested restricted shares at December 31, 2015 2,296,349 $ 2.63 Granted 1,764,645 1.19 Vested (1,487,269 ) 2.37 Forfeited (128,435 ) 1.88 Outstanding non-vested restricted shares at December 31, 2016 2,445,290 $ 1.79 1.49 $ 3,790
Schedule of Share-based Compensation, Stock Options, Activity	The table below provides a summary of PBUs as of the date indicated: PBUs Weighted Average Fair per Unit Unvested PBUs at December 31, 2015 1,283,167 $ 3.24 Granted 801,397 1.62 Vested (448,634 ) 2.76 Forfeited (160,200 ) 3.40 Unvested PBUs at December 31, 2016 1,475,730 $ 2.49
Schedule of Unrecognized Compensation Cost, Nonvested Awards	As of December 31, 2016, the Company had approximately $2.7 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods: Amount (in thousands) 2017 $ 1,913 2018 717 2019 56 Total $ 2,686
Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands, except per share data) Weighted average grant date fair value per restricted share $ 1.19 $ 2.40 $ 5.85 Total fair value of restricted shares vested $ 3,530 $ 3,794 $ 3,497

Interest Expense (Tables)

Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2016
Interest Expense [Abstract]
Schedule Of Components Of Interest Expense	The following tables summarize the components of the Company’s interest expense for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands) Interest expense: Cash and accrued $ 33,368 $ 30,981 $ 28,851 Amortization of deferred financing costs (1) 4,980 3,584 3,067 Capitalized interest (3,102 ) (3,879 ) (4,347 ) Total interest expense $ 35,246 $ 30,686 $ 27,571 (1)

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Contingency [Line Items]
Schedule of (Loss) Income before Income Taxes	The following table summarizes the components of the Company’s (loss) income before income taxes for the periods indicated: For the Year Ended December 31, 2016 2015 2014 (in thousands) United States $ (89,061 ) $ (459,507 ) $ 50,953 Total income (loss) before income taxes $ (89,061 ) $ (459,507 ) $ 50,953
Schedule of Effective Income Tax Rate Reconciliation	The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands) Expected income tax provision (benefit) at statutory rate $ (31,172 ) $ (160,827 ) $ 17,833 State tax, tax effected (1,408 ) (7,799 ) 803 Stock-based compensation expense (benefit) 1,995 255 (1,291 ) Non-deductible compensation 178 — — Other 693 17 38 Other changes in valuation allowance 29,714 168,354 (17,383 ) Actual income tax provision $ — $ — $ —
US
Income Tax Contingency [Line Items]
Schedule of Deferred Tax Assets and Liabilities	The components of the Company’s U.S. deferred taxes are as follows: As of December 31, 2016 2015 (in thousands) Deferred tax asset (liability): Capital assets $ 33,131 $ 10,485 Stock-based compensation 2,499 4,243 Net operating loss carry forwards 196,775 187,963 Foreign tax credit carry forwards 50,681 50,681 Valuation allowance (283,086 ) (253,372 ) Net deferred tax asset $ — $ —

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	For the Years Ended December 31, 2016 2015 2014 (in thousands, except per share and share data) Net (loss) income attributable to common stockholders $ (103,534 ) $ (473,980 ) $ 36,529 Weighted average shares of common stock outstanding - basic 111,367,452 77,511,677 63,270,733 Incremental shares from unvested restricted shares — — 2,451,903 Incremental shares from outstanding stock options — — 97,491 Incremental shares from outstanding PBUs — — 672,462 Weighted average shares of common stock outstanding - diluted 111,367,452 77,511,677 66,492,589 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (6.11 ) $ 0.58 Diluted $ (0.93 ) $ (6.11 ) $ 0.55 Shares of common stock excluded from denominator as anti-dilutive: Unvested restricted shares 438,948 177,663 34,058 Unvested PBUs 487,995 17,589 — Total 926,943 195,252 34,058

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Schedule of future minimum annual rental commitments	As of December 31, 2016, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: 2017 $ 447 2018 733 2019 617 2020 620 2021 and thereafter 834 $ 3,251

Concentration of Risk and Sig38

Concentration of Risk and Significant Customers (Tables)	12 Months Ended
	Dec. 31, 2016
Risks And Uncertainties [Abstract]
Schedules of Concentration of Risk, by Risk Factor	The following table provides information regarding the approximate percentages of the Company's oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated: For the Years Ended December 31, 2016 2015 2014 Appalachian Basin 5 % 17 % 39 % Mid-Continent 95 % 83 % 61 % The following table provides information regarding the Company’s significant customers whom accounted for more than 10% of the Company’s oil, condensate, natural gas and NGLs revenues, excluding hedge impact, for the periods indicated: For the Years Ended December 31, 2016 2015 2014 Sunoco 67 % 62 % 37 % Superior 12 % 6 % 5 % SEI (1) 5 % 22 % 50 % (1) SEI filed for Chapter 7 bankruptcy on June 3, 2016.

Statement of Cash Flows - Suppl

Statement of Cash Flows - Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Statement of Cash Flows Supplemental Information	The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements: For the Years Ended December 31, 2016 2015 2014 (in thousands) Cash paid for interest, net of capitalized amounts $ 30,480 $ 26,859 $ 24,632 Non-cash transactions: Capital expenditures (excluded from) included in accounts payable and accrued drilling costs $ (82 ) $ (26,228 ) $ 12,777 Capital expenditures included in accounts receivable 409 — 4,077 Asset retirement obligation included in oil and natural gas properties 432 526 221 Asset retirement obligation for property disposals (1,045 ) (416 ) (645 ) Application of advances to operators (347 ) 11,445 58,326 Other — 5 (11 )

Quarterly Consolidated Financ40

Quarterly Consolidated Financial Data - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2016 and 2015: 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 14,811 $ 12,153 $ 13,003 $ 18,287 (Loss) income from operations (1) (60,592 ) (5,142 ) 7,959 3,929 Loss before provision for income taxes (69,857 ) (14,481 ) (178 ) (4,545 ) Net loss (69,857 ) (14,481 ) (178 ) (4,545 ) Dividends on preferred stock 3,618 3,619 3,618 3,618 Net loss attributable to common stockholders (73,475 ) (18,100 ) (3,796 ) (8,163 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Diluted $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Weighted average shares of common stock outstanding: Basic 78,788,133 104,009,337 129,301,817 132,936,419 Diluted 78,788,133 104,009,337 129,301,817 132,936,419 (1) 2015 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 34,372 $ 21,928 $ 28,386 $ 22,608 Income (loss) from operations (1) 8,172 (107,462 ) (180,272 ) (149,272 ) Income (loss) before provision for income taxes 614 (114,395 ) (188,201 ) (157,525 ) Net income (loss) 614 (114,395 ) (188,201 ) (157,525 ) Dividends on preferred stock 3,618 3,619 3,618 3,618 Net loss attributable to common stockholders (3,004 ) (118,014 ) (191,819 ) (161,143 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Diluted $ (0.04 ) $ (1.52 ) $ (2.47 ) $ (2.07 ) Weighted average shares of common stock outstanding: Basic 77,114,826 77,611,167 77,628,120 77,685,049 Diluted 77,114,826 77,611,167 77,628,120 77,685,049 (1) Income (loss) from operations for the second, third and fourth quarters include impairment of oil and natural gas properties of $100.2 million, $182.0 million and $144.8 million, respectively.

Supplemental Oil and Gas Disc41

Supplemental Oil and Gas Disclosures - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2016
Reserve Quantities [Line Items]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities in the U.S. for the periods indicated: As of December 31, 2016 2015 2014 (in thousands) Proved properties $ 1,253,061 $ 1,286,373 $ 1,124,367 Unproved properties 67,333 92,609 128,274 Total oil and natural gas properties 1,320,394 1,378,982 1,252,641 Less: Impairment of proved oil and natural gas properties (813,314 ) (764,817 ) (337,939 ) Accumulated depreciation, depletion and amortization (315,373 ) (286,020 ) (223,555 ) Net capitalized costs $ 191,707 $ 328,145 $ 691,147
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods indicated: For the Years Ended December 31, 2016 2015 2014 (in thousands) Property acquisition Proved $ 570 $ 15,615 $ — Unproved 38,941 50,434 41,475 Exploration 19,761 53,290 127,384 Development 3,810 54,316 57,913 Total costs incurred $ 63,082 $ 173,655 $ 226,772
Results of Operations for Oil and Gas Producing Activities Disclosure	The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated: For the Year Ended December 31, 2016 2015 2014 (in thousands, except per Mcfe data) Oil, condensate, natural gas and NGLs sales, including commodity derivatives $ 58,254 $ 107,294 $ 171,418 Production expenses (24,217 ) (28,792 ) (29,735 ) Impairment of oil and natural gas properties (48,497 ) (426,878 ) — Depreciation, depletion and amortization (29,353 ) (62,465 ) (45,765 ) Results of producing activities $ (43,813 ) $ (410,841 ) $ 95,918 Depreciation, depletion and amortization per MBoe $ 10.23 $ 12.67 $ 12.34
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations: For the Years Ended December 31, 2016 2015 2014 Natural gas, per MMBtu Henry Hub $ 2.48 $ 2.59 $ 4.35 Oil, per barrel: WTI spot $ 42.75 $ 50.28 $ 94.99
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2016, 2015 and 2014: Change in Proved Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) Proved reserves as of December 31, 2013 14,718 180,710 9,798 54,634 2014 Activity: Extensions and discoveries (4) 13,137 121,672 9,394 42,810 Revisions of previous estimates 1,780 (2,465 ) 7,205 8,574 Production (975 ) (11,598 ) (800 ) (3,708 ) Sales in place (24 ) (1,314 ) (4 ) (247 ) Proved reserves as of December 31, 2014 28,636 287,005 25,593 102,063 2015 Activity: Extensions and discoveries (5) 4,777 14,114 2,244 9,374 Revisions of previous estimates (6) (8,962 ) (182,600 ) (13,873 ) (53,268 ) Production (1,425 ) (13,759 ) (1,212 ) (4,931 ) Purchases in place 1,270 4,965 873 2,971 Sales in place (94 ) (1,274 ) (26 ) (332 ) Proved reserves as of December 31, 2015 24,202 108,451 13,599 55,877 2016 Activity: Extensions and discoveries 1,582 7,213 898 3,681 Revisions of previous estimates (7) (9,890 ) (17,825 ) (3,317 ) (16,177 ) Production (1,105 ) (6,145 ) (739 ) (2,869 ) Sales in place (1,033 ) (53,841 ) (4,929 ) (14,935 ) Proved reserves as of December 31, 2016 13,756 37,853 5,512 25,577 (1) Thousand barrels (2) Million cubic feet or million cubic feet equivalent, as applicable (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. (4) Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations. (5) All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. (6) The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. (7) The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position. Proved Developed and Undeveloped Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) December 31, 2014 Proved developed reserves 6,968 114,564 10,726 36,789 Proved undeveloped reserves 21,668 172,441 14,867 65,274 Total 28,636 287,005 25,593 102,063 December 31, 2015 Proved developed reserves 7,181 77,966 8,240 28,415 Proved undeveloped reserves 17,021 30,485 5,359 27,462 Total 24,202 108,451 13,599 55,877 December 31, 2016 Proved developed reserves 6,037 22,786 3,181 13,015 Proved undeveloped reserves 7,719 15,067 2,332 12,562 Total 13,756 37,853 5,512 25,577 (1) Thousand barrels (2) Million cubic feet (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves in the U.S. is presented below (in thousands): December 31, 2014: Future cash inflows $ 3,855,227 Future production costs (1,048,554 ) Future development costs (611,602 ) Future income taxes (486,593 ) Future net cash flows 1,708,478 10% annual discount for estimated timing of cash flows (891,739 ) Standardized measure of discounted future cash flows $ 816,739 December 31, 2015: Future cash inflows $ 1,425,734 Future production costs (547,484 ) Future development costs (365,123 ) Future income taxes (1) — Future net cash flows 513,127 10% annual discount for estimated timing of cash flows (283,324 ) Standardized measure of discounted future cash flows $ 229,803 December 31, 2016: Future cash inflows $ 710,370 Future production costs (328,010 ) Future development costs (123,214 ) Future income taxes (1) — Future net cash flows 259,146 10% annual discount for estimated timing of cash flows (117,815 ) Standardized measure of discounted future cash flows $ 141,331 (1) No future taxes payable has been included in the determination of discounted future net cash flows for 2015 and 2016 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	The principal sources of changes in the standardized measure of future net cash flows are as follows (in thousands): December 31, 2013 $ 515,829 Extensions and discoveries, less related costs 369,806 Sale of natural gas and oil, net of production costs (122,114 ) Sales of reserves in place (1,475 ) Revisions of previous quantity estimates 101,044 Net change in income tax (95,245 ) Net change in prices and production costs 59,786 Accretion of discount (3,996 ) Development costs incurred 37,461 Net change in estimated future development costs (1,276 ) Change in production rates (timing) and other (43,081 ) December 31, 2014 $ 816,739 Extensions and discoveries, less related costs 71,547 Sale of natural gas and oil, net of production costs (53,914 ) Purchases of reserves in place 9,937 Sales of reserves in place (4,853 ) Revisions of previous quantity estimates (324,036 ) Net change in income tax 171,946 Net change in prices and production costs (604,074 ) Accretion of discount 98,869 Development costs incurred 10,500 Net change in estimated future development costs 31,131 Change in production rates (timing) and other 6,011 December 31, 2015 $ 229,803 Extensions and discoveries, less related costs 19,270 Sale of natural gas and oil, net of production costs (36,900 ) Sales of reserves in place (16,023 ) Revisions of previous quantity estimates (115,785 ) Net change in income tax — Net change in prices and production costs (43,270 ) Accretion of discount (16,461 ) Net change in estimated future development costs 119,531 Change in production rates (timing) and other 1,166 December 31, 2016 $ 141,331
Key Natural Gas and Oil Prices
Reserve Quantities [Line Items]
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	The following table provides the key benchmark natural gas and oil prices used as of the periods indicated to calculate reserves: As of December 31, 2016 2015 Natural gas (per MMBtu): Henry Hub $ 2.48 $ 2.59 Oil (per Bbl): WTI spot $ 42.75 $ 50.28

Description of Business (Narrat

Description of Business (Narrative) (Details) - USD ($) $ in Thousands	Apr. 08, 2016	Feb. 19, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Exploratory Wells Drilled [Line Items]
Proceeds from sale of oil and natural gas properties			$ 121,273	$ 47,314	$ 5,530
Appalachian Basin
Exploratory Wells Drilled [Line Items]
Proceeds from sale of oil and natural gas properties	$ 75,700	$ 80,000
Suspense liability transferred to buyer	$ 3,500

Summary of Significant Accoun43

Summary of Significant Accounting Policies (Narrative) (Details)	Mar. 03, 2017USD ($)$ / shares	Mar. 02, 2017Director	Feb. 16, 2017USD ($)$ / sharesshares	Feb. 15, 2017$ / shares	Jan. 27, 2017Right$ / shares	Jan. 31, 2017shares	Dec. 31, 2016USD ($)well$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)shares	Jan. 10, 2017USD ($)	Dec. 31, 2013USD ($)
Accounting Policies [Line Items]
Aggregate principal amount							$ 325,000,000	$ 325,000,000
Common stock, par value | $ / shares							$ 0.001	$ 0.001
Proceeds from issuance of common stock, net of issuance costs							$ 69,224,000	$ 0	$ 101,319,000
Term loan amount							$ 319,863,000	$ 316,476,000
Common stock, shares issued | shares							150,377,870	80,024,218
Common stock, shares outstanding | shares							150,377,870	80,024,218
Cash and cash equivalents							$ 71,529,000	$ 50,074,000	11,008,000		$ 32,393,000
Discount rate for oil and natural gas prices held constant							10.00%
Capitalized interest							$ 3,100,000	$ 3,900,000	$ 4,300,000
Expected Forfeitures (percentage)							19.10%	17.50%	25.50%
Adjustment to retained earnings							$ 657,000
Adjustment to reduce forfeiture rate							0.00%
Canada
Accounting Policies [Line Items]
Number of gas wells | well							2
Minimum | Furniture and equipment
Accounting Policies [Line Items]
Estimated useful lives							3 years
Maximum | Furniture and equipment
Accounting Policies [Line Items]
Estimated useful lives							7 years
Common Stock
Accounting Policies [Line Items]
Issuance of common shares - cash, net of offering costs (shares) | shares							50,000,000		17,000,000
Series C Preferred Stock | 2017 Rights Agreement
Accounting Policies [Line Items]
Dividend payment terms							The dividend was paid to stockholders of record on February 10, 2017. Each Right entitles the registered holder, subject to the terms of the 2017 Rights Agreement to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $10.74, subject to certain adjustments.
Subsequent Events
Accounting Policies [Line Items]
Common stock volume weighted average trading price per share | $ / shares				$ 1.7002
Threshold percentage above the VWAP of common stock	30.00%
Interest rate, annual increase in increment percentage, if not converted	15.00%
Subsequent Events | Scenario One
Accounting Policies [Line Items]
Number of members can nominate to board of directors | Director		2
Number of members of board of directors to expand | Director		8
Subsequent Events | Scenario Two
Accounting Policies [Line Items]
Number of members can nominate to board of directors | Director		1
Subsequent Events | Minimum | Scenario One
Accounting Policies [Line Items]
Purchasers beneficial ownership percentage		15.00%
Subsequent Events | Minimum | Scenario Two
Accounting Policies [Line Items]
Purchasers beneficial ownership percentage		5.00%
Subsequent Events | Maximum | Scenario Two
Accounting Policies [Line Items]
Purchasers beneficial ownership percentage		15.00%
Subsequent Events | Revolving Credit Facility
Accounting Policies [Line Items]
Repayment of debt	$ 69,200,000
Subsequent Events | First Lien Secured Term Loan
Accounting Policies [Line Items]
Interest rate	8.50%
Debt instrument maturity date	Mar. 3, 2022
Frequency of interest payment	quarterly
Subsequent Events | Securities Purchase Agreement | Ares Management, LLC
Accounting Policies [Line Items]
Number of consecutive trading days used in volume-weighted average trading price			30 days	30 days
Common stock volume weighted average trading price per share | $ / shares				$ 1.7002
Percentage of total issued and outstanding of common share issued to purchaser						18.80%
Common stock, shares issued | shares						156,715,833
Common stock, shares outstanding | shares						156,715,833
Subsequent Events | Securities Purchase Agreement | Ares Management, LLC | Minimum
Accounting Policies [Line Items]
Purchasers beneficial ownership percentage						10.00%
Subsequent Events | Securities Purchase Agreement | Ares Management, LLC | Revolving Credit Facility
Accounting Policies [Line Items]
Repayment of debt	$ 69,200,000
Subsequent Events | Securities Purchase Agreement | Ares Management, LLC | First Lien Secured Term Loan
Accounting Policies [Line Items]
Term loan amount			$ 250,000,000
Subsequent Events | Securities Purchase Agreement | Ares Management, LLC | Common Stock
Accounting Policies [Line Items]
Common stock, par value | $ / shares			$ 0.001
Issuance of common shares - cash, net of offering costs (shares) | shares			29,408,305
Proceeds from issuance of common stock, net of issuance costs			$ 50,000,000
Subsequent Events | Series C Preferred Stock | 2017 Rights Agreement
Accounting Policies [Line Items]
Number of rights issued on dividend declared | Right					1
Dividend payment terms					The dividend was paid to stockholders of record on February 10, 2017. Each Right entitles the holder, subject to the terms of the 2017 Rights Agreement, to purchase one one-thousandth of a share of Series C Preferred Stock at a price of $10.74, subject to certain adjustments.
Preferred stock, dividend rate, per share | $ / shares					$ 10.74
Dividends payable record date					Feb. 10, 2017
Amendment No. 10 | Subsequent Events
Accounting Policies [Line Items]
Preferred dividends payment, minimum required cash liquidity										$ 30,000,000
Convertible Notes due 2022
Accounting Policies [Line Items]
Debt instrument, redemption description							If the Company obtains the Requisite Stockholder Approval, then the Company will have the right to redeem the Notes (i) on or after March 3, 2019 if the common stock trades above 150% of the conversion price for periods specified in the Indenture; and (ii) on or after March 1, 2021 without regard to such condition, in each case at par plus accrued interest.
Convertible Notes due 2022 | Subsequent Events
Accounting Policies [Line Items]
Interest rate	6.00%
Debt conversion ratio, number of shares per $1,000 principal amount	452.4355
Debt conversion ratio, principal amount, denominator	$ 1,000
Convertible notes, initial conversion price | $ / shares	$ 2.2103
Debt instrument, redemption description	If the Company obtains the Requisite Stockholder Approval, then the Company will have the right to redeem the Notes (i) on or after the second anniversary of the Closing Date if the Common Stock trades above 150% of the conversion price for periods specified in the Indenture; and (ii) on or after March 1, 2021 without regard to such condition, in each case at par plus accrued interest.
Threshold percentage of conversion price for redemption upon stockholder approval	150.00%
Debt instrument, redemption period, start date	Mar. 1, 2021
Debt instrument maturity date	Mar. 1, 2022
Debt instrument, default, description	The Indenture provides that a number of events will constitute an Event of Default (as defined in the Indenture), including, among other things: (i) a failure to pay the Notes when due at maturity, upon redemption or repurchase; (ii) failure to pay interest for 30 days; (iii) the Company’s failure to deliver certain notices; (iv) a default in the Company’s obligation to convert the Notes; (v) the Company’s failure to comply with certain covenants relating to merger, consolidation or sale of assets; (vi) the Company’s failure to comply, for 60 days following notice, with any of the other covenants or agreements in the Indenture; (vii) a default, which is not cured within 30 days, by the Company or any Restricted Subsidiaries (as defined in the Indenture) with respect to any mortgages or any indebtedness for money borrowed of at least $15 million; (viii) one or more final judgments against the Company or any of its Restricted Subsidiaries for the payment of at least $15 million; (ix) the Company’s failure to make any payments required under that certain development agreement; (x) causing any Guarantee (as defined in the Indenture) to cease to be in full force and effect; (xi) the cessation to be in full force and effect of any of the collateral agreements related to the Ares Investment Transaction; and (xii) certain events of bankruptcy or insolvency.
Debt instrument, debt default, amount	$ 15,000,000
Aggregate principal amount of the then outstanding notes, percentage	25.00%
Interest rate, annual increase in increment percentage, if not converted	15.00%
Convertible Notes due 2022 | Subsequent Events | Securities Purchase Agreement | Ares Management, LLC
Accounting Policies [Line Items]
Aggregate principal amount			$ 125,000,000
Senior Secured Notes Due 2018
Accounting Policies [Line Items]
Aggregate principal amount							$ 325,000,000
Interest rate							8.625%
Debt instrument maturity date							May 15, 2018
Senior Secured Notes Due 2018 | Subsequent Events
Accounting Policies [Line Items]
Repayment of debt	$ 325,000,000
Senior Secured Notes Due 2018 | Subsequent Events | Ares Management, LLC
Accounting Policies [Line Items]
Aggregate principal amount	$ 325,000,000
Interest rate	8.625%
Debt instrument maturity date	May 15, 2018
Senior Secured Notes Due 2018 | Subsequent Events | Securities Purchase Agreement | Ares Management, LLC
Accounting Policies [Line Items]
Repayment of debt	$ 325,000,000
Interest rate	8.625%
Debt instrument redemption price percentage	102.156%

Summary of Significant Accoun44

Summary of Significant Accounting Policies (Schedule of Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Allowance for Doubtful Accounts Receivable [Roll Forward]
Allowance for doubtful accounts, beginning of year	$ 0	$ 0	$ 507
Expense	1,953	0	0
Reductions/write-offs	0	0	(507)
Allowance for doubtful accounts, end of year	$ 1,953	$ 0	$ 0

Summary of Significant Accoun45

Summary of Significant Accounting Policies (Schedule of Deferred Financing Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Deferred charges	$ 2,971	$ 1,686
Accumulated amortization	(2,295)	(701)
Deferred charges, net	$ 676	$ 985

Property, Plant and Equipment46

Property, Plant and Equipment (Narrative) (Details) Boe in Millions

Mar. 09, 2017USD ($)

Jan. 20, 2017USD ($)

Dec. 31, 2016USD ($)Boewell

Nov. 18, 2016USD ($)

Oct. 19, 2016USD ($)awell

Oct. 14, 2016awellTownshipTranche

Apr. 08, 2016USD ($)

Feb. 19, 2016USD ($)

Dec. 16, 2015USD ($)awell

Dec. 31, 2016USD ($)Boewell

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Mar. 06, 2017well

Jul. 06, 2015USD ($)awell

Property, Plant and Equipment [Line Items]

Asset retirement obligation

$ 1,500,000

$ 1,500,000

$ 2,400,000

$ 2,400,000

Reclassification of unproved properties to proved properties

14,400,000

Estimated proved reserves volume | Boe

25.6

25.6

Fair market value, discounted present rate

10.00%

Proceeds from sale of natural gas and oil properties

$ 121,273,000

47,314,000

$ 5,530,000

Percentage difference of fair value to purchase price

6.00%

Assets, fair value adjustment

$ 0

Husky Acquisition

Property, Plant and Equipment [Line Items]

Net acres | a

11,000

Gross wells | well

103

Net wells | well

10.2

Acquisition of oil and natural gas properties

$ 42,700,000

Revenue suspense liability assumed

358,000

Escrow for pending resolution of title defects and purchase of overrides recorded in other assets

4,300,000

Fair market valuation amount

44,600,000

Husky Acquisition | General and Administrative Expense

Property, Plant and Equipment [Line Items]

Transaction and integration costs

$ 1,500,000

Appalachian Basin

Property, Plant and Equipment [Line Items]

Proceeds from sale of natural gas and oil properties

$ 75,700,000

$ 80,000,000

Suspense liability transferred to buyer

$ 3,500,000

Gain or loss of assets

$ 0

Mid Continent Divestiture

Property, Plant and Equipment [Line Items]

Net wells | well

16.7

Gross wells | well

38

Gross acres (acres) | a

29,500

Net acres (acres) | a

19,200

Net cash purchase price of divestiture

$ 46,500,000

Development Agreement

Property, Plant and Equipment [Line Items]

Number of wells completed | well

4

4

Development Agreement | Investor

Property, Plant and Equipment [Line Items]

Fair market value, discounted present rate

15.00%

Appalachian Basin

Property, Plant and Equipment [Line Items]

Reclassification of unproved properties to proved properties

$ 14,400,000

Oklahoma | Red Bluff | Canadian County Property

Property, Plant and Equipment [Line Items]

Consideration on sale of property

$ 71,000,000

Net acres to be sold | a

25,300

Net acres allocated | a

19,100

Gross wells to be sold | well

25

Net wells to be sold | well

11.2

Contingent consideration on sale of property

$ 10,000,000

Purchase price allocated to producing properties

$ 1,400,000

Consideration on sale of property received

$ 48,600,000

Oklahoma | Development Agreement

Property, Plant and Equipment [Line Items]

Investor funding percentage on working interest portion of drilling and completion cost

90.00%

Investors percentage of Gastar's working interest in each new well

80.00%

Percentage of costs to pay to obtain 20% working interest

10.00%

Percentage on working interest in each new well

20.00%

Number of tranches | Tranche

3

Number of wells in each tranche | well

20

Number of wells in Meramec formation | well

18

Number of wells in Osage formation | well

2

Percentage of internal rate of return one

15.00%

Percentage of working interest on achievement of 15% internal rate of return

60.00%

Percentage of internal rate of return two

20.00%

Percentage of working interest on achievement of 20% internal rate of return

90.00%

Description of working interest on achievement of internal rate of returns

With respect to each 20-well tranche, when the Investor has achieved an aggregate 15% internal rate of return for its investment in the tranche, its interest will be reduced from 80% to 40% of the Company’s original working interest and the Company’s working interest increases from 20% to 60% of the Company’s original working interest. When a tranche internal rate of return of 20% is achieved by the Investor, its working interest decreases to 10% and the Company’s working interest increases to 90% of the working interest originally owned by the Company.

Oklahoma | Development Agreement | Investor

Property, Plant and Equipment [Line Items]

Number of townships covered | Township

3

Gross acres | a

32,900

Net acres | a

19,100

Percentage of working interest on achievement of 15% internal rate of return

40.00%

Percentage of working interest on achievement of 20% internal rate of return

10.00%

Oklahoma | Development Agreement | Investor | Maximum

Property, Plant and Equipment [Line Items]

Number of operated wells | well

60

Subsequent Event | Development Agreement

Property, Plant and Equipment [Line Items]

Number of wells completed | well

9

Subsequent Event | West Virginia

Property, Plant and Equipment [Line Items]

Consideration on sale of property

$ 200,000

Subsequent Event | Oklahoma | Red Bluff | Canadian County Property

Property, Plant and Equipment [Line Items]

Consideration on sale of property received

$ 9,500,000

Contingent payment on sale of property received

$ 5,000,000

Property, Plant And Equipment47

Property, Plant And Equipment (Schedule of Property Plant and Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Unproved properties	$ 67,333	$ 92,609
Proved properties	1,253,061	1,286,373
Total oil and natural gas properties	1,320,394	1,378,982
Total property and equipment	1,323,016	1,382,050
Impairment of proved natural gas and oil properties	(813,314)	(764,817)
Accumulated depreciation, depletion and amortization	(317,698)	(288,299)
Total accumulated depreciation, depletion and amortization	(1,131,012)	(1,053,116)
Total property, plant and equipment, net	192,004	328,934
Total oil and natural gas properties
Property, Plant and Equipment [Line Items]
Unproved properties	67,333	92,609
Proved properties	1,253,061	1,286,373
Total oil and natural gas properties	1,320,394	1,378,982
Furniture and equipment
Property, Plant and Equipment [Line Items]
Total property and equipment	$ 2,622	$ 3,068

Property, Plant and Equipment48

Property, Plant and Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Unproved properties, excluded from amortization:
Drilling in progress costs	$ 1,100	$ 1,533
Acreage acquisition costs	58,857	82,560
Capitalized interest	7,376	8,516
Total unproved properties excluded from amortization	$ 67,333	$ 92,609

Property, Plant and Equipment49

Property, Plant and Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) $ in Thousands		3 Months Ended												12 Months Ended
		Dec. 31, 2016$ / MMBTU$ / bbl	Sep. 30, 2016$ / MMBTU$ / bbl	Jun. 30, 2016$ / MMBTU$ / bbl	Mar. 31, 2016USD ($)$ / MMBTU$ / bbl	Dec. 31, 2015USD ($)$ / MMBTU$ / bbl	Sep. 30, 2015USD ($)$ / MMBTU$ / bbl	Jun. 30, 2015USD ($)$ / MMBTU$ / bbl	Mar. 31, 2015$ / MMBTU$ / bbl	Dec. 31, 2014$ / MMBTU$ / bbl	Sep. 30, 2014$ / MMBTU$ / bbl	Jun. 30, 2014$ / MMBTU$ / bbl	Mar. 31, 2014$ / MMBTU$ / bbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Impairment recorded (pre-tax) (in thousands) | $					$ 48,497	$ 144,760	$ 181,966	$ 100,152						$ 48,497	$ 426,878	$ 0
Natural Gas Per Thousand Cubic Feet
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe | $ / MMBTU	[1]	2.48	2.28	2.24	2.40	2.59	3.06	3.39	3.88	4.35	4.24	4.10	3.99
Crude Oil And N G L Per Barrel
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average price per Mcfe | $ / bbl	[1]	42.75	41.68	43.12	46.26	50.28	59.21	71.68	82.72	94.99	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.

Property, Plant And Equipment50

Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Husky Acquisition
Business Acquisition [Line Items]
Revenues		$ 115,147
Net loss		$ (470,874)
Loss per share, Basic		$ (6.07)
Loss per share, Diluted		$ (6.07)
Appalachian Basin
Business Acquisition [Line Items]
Revenues	$ 55,177	$ 93,783
Net loss	$ (98,459)	$ (464,788)
Loss per share, Basic	$ (0.88)	$ (6)
Loss per share, Diluted	$ (0.88)	$ (6)

Property, Plant And Equipment51

Property, Plant And Equipment (Schedule of Assets Acquired) (Details) - Husky Acquisition $ in Thousands	Dec. 16, 2015USD ($)
Business Acquisition [Line Items]
Cash consideration	$ 42,085
Total purchase price	42,085
Unproved properties	27,875
Proved properties	15,592
Other	(1,382)
Total assets acquired	$ 42,085

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($)	Mar. 03, 2017	Feb. 16, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 30, 2017	Feb. 15, 2017	Jan. 10, 2017
Line of Credit Facility [Line Items]
Aggregate principal amount			$ 325,000,000	$ 325,000,000
Proceeds from issuance of common stock, net of issuance costs			69,224,000	0	$ 101,319,000
Term loan amount			$ 319,863,000	$ 316,476,000
Common Stock
Line of Credit Facility [Line Items]
Issuance of common shares - cash, net of offering costs (shares)			50,000,000		17,000,000
Convertible Notes due 2022
Line of Credit Facility [Line Items]
Debt instrument, redemption description			If the Company obtains the Requisite Stockholder Approval, then the Company will have the right to redeem the Notes (i) on or after March 3, 2019 if the common stock trades above 150% of the conversion price for periods specified in the Indenture; and (ii) on or after March 1, 2021 without regard to such condition, in each case at par plus accrued interest.
Senior Secured Notes Due 2018
Line of Credit Facility [Line Items]
Aggregate principal amount			$ 325,000,000
Interest rate			8.625%
Debt instrument maturity date			May 15, 2018
Debt instrument interest rate description			The Former Notes bore interest at a rate of 8.625% per year, payable semiannually in arrears on May 15 and November 15 of each year, beginning on November 15, 2013.
Second Amended and Restated Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility scheduled maturity date			Nov. 14, 2017
Amendment No. 10 | Scenario Forecast
Line of Credit Facility [Line Items]
Agreed additional indebtedness to pay down						$ 8,100,000
Indenture
Line of Credit Facility [Line Items]
Debt instrument interest rate description			The Notes bear interest at 6.0% per annum and will mature on March 1, 2022, unless earlier repurchased, redeemed or converted in accordance with the terms of the Indenture prior to such date.
Subsequent Events
Line of Credit Facility [Line Items]
Senior notes, interest rate increments	15.00%
Common stock volume weighted average trading price per share							$ 1.7002
Subsequent Events | Convertible Notes due 2022
Line of Credit Facility [Line Items]
Interest rate	6.00%
Debt instrument maturity date	Mar. 1, 2022
Convertible notes, initial conversion price	$ 2.2103
Threshold percentage of conversion price for redemption upon stockholder approval	150.00%
Debt instrument, redemption description	If the Company obtains the Requisite Stockholder Approval, then the Company will have the right to redeem the Notes (i) on or after the second anniversary of the Closing Date if the Common Stock trades above 150% of the conversion price for periods specified in the Indenture; and (ii) on or after March 1, 2021 without regard to such condition, in each case at par plus accrued interest.
Debt instrument, redemption period, start date	Mar. 1, 2021
Senior notes, interest rate increments	15.00%
Subsequent Events | Senior Secured Notes Due 2018
Line of Credit Facility [Line Items]
Repayment of debt	$ 325,000,000
Subsequent Events | Amendment No. 10
Line of Credit Facility [Line Items]
Preferred dividends payment, minimum required cash liquidity								$ 30,000,000
Subsequent Events | Indenture
Line of Credit Facility [Line Items]
Aggregate principal amount	$ 125,000,000
Interest rate	6.00%
Debt instrument maturity date	Mar. 1, 2022
Subsequent Events | First Lien Secured Term Loan
Line of Credit Facility [Line Items]
Interest rate	8.50%
Frequency of interest payment	quarterly
Debt instrument maturity date	Mar. 3, 2022
Subsequent Events | Revolving Credit Facility
Line of Credit Facility [Line Items]
Repayment of debt	$ 69,200,000
Subsequent Events | Ares Management, LLC | Senior Secured Notes Due 2018
Line of Credit Facility [Line Items]
Aggregate principal amount	$ 325,000,000
Interest rate	8.625%
Debt instrument maturity date	May 15, 2018
Subsequent Events | Ares Management, LLC | Securities Purchase Agreement
Line of Credit Facility [Line Items]
Common stock volume weighted average trading price per share							$ 1.7002
Subsequent Events | Ares Management, LLC | Securities Purchase Agreement | Common Stock
Line of Credit Facility [Line Items]
Issuance of common shares - cash, net of offering costs (shares)		29,408,305
Proceeds from issuance of common stock, net of issuance costs		$ 50,000,000
Subsequent Events | Ares Management, LLC | Securities Purchase Agreement | Convertible Notes due 2022
Line of Credit Facility [Line Items]
Aggregate principal amount		125,000,000
Subsequent Events | Ares Management, LLC | Securities Purchase Agreement | Senior Secured Notes Due 2018
Line of Credit Facility [Line Items]
Repayment of debt	$ 325,000,000
Interest rate	8.625%
Subsequent Events | Ares Management, LLC | Securities Purchase Agreement | First Lien Secured Term Loan
Line of Credit Facility [Line Items]
Term loan amount		$ 250,000,000
Subsequent Events | Ares Management, LLC | Securities Purchase Agreement | Revolving Credit Facility
Line of Credit Facility [Line Items]
Repayment of debt	$ 69,200,000

Long-Term Debt - Summary of Not

Long-Term Debt - Summary of Notes Balance (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Notes, principal balance	$ 325,000,000	$ 325,000,000
Unamortized discounts	4,342,000	7,151,000
Deferred financing costs	795,000	1,373,000
Notes, net	$ 319,863,000	$ 316,476,000

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, beginning of year	$ 6,086	$ 5,557	$ 6,063
Liabilities incurred during period	196	302	305
Liabilities settled during period	(90)	(37)	(704)
Accretion expense	368	502	506
Revision in previous estimates and other	17	178	32
Deletions related to property disposals	(1,045)	(416)	(645)
Asset retirement obligation, end of year	$ 5,532	$ 6,086	$ 5,557

Asset Retirement Obligation (Na

Asset Retirement Obligation (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation	$ 89	$ 89

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Amount reclassified from unproved to proved properties	$ 14.4
Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of long-term debt	$ 377.5	$ 403.1

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets:
Cash and cash equivalents	$ 71,529	$ 50,074
Assets, Commodity derivative contracts	7,850	24,869
Liabilities:
Liabilities, Commodity derivative contracts	(338)	(451)
Total	79,041	74,492
Level 1
Assets:
Cash and cash equivalents	71,529	50,074
Liabilities:
Total	71,529	50,074
Level 3
Assets:
Assets, Commodity derivative contracts	7,850	24,869
Liabilities:
Liabilities, Commodity derivative contracts	(338)	(451)
Total	$ 7,512	$ 24,418

Fair Value Measurements (Net Ch

Fair Value Measurements (Net Change in Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2016 and 2015		$ (13,600)	$ (1,900)	$ 23,900
Fair Value, Measurements, Recurring
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		24,418	27,502
Total (losses) gains included in earnings		(2,863)	24,589
Purchases		565	1,326
Issuances		(165)	(1,313)
Settlements	[1]	(14,443)	(27,686)
Balance at end of period		7,512	24,418	$ 27,502
The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2016 and 2015		$ (13,622)	$ (1,890)
[1]	Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations

Derivative Instruments and He59

Derivative Instruments and Hedging Activity (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Change in fair value of commodity derivative contracts	$ (13.6)	$ (1.9)	$ 23.9

Derivative Instruments and He60

Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2016MMBTU$ / MMBTU$ / bblbbl
Costless Three-way Collar 1 - 2017 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | MMBTU	5,000
Total of Notional Volume (MMBtu) | MMBTU	1,825,000
Costless Three-way Collar 1 - 2017 | Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Costless Three-way Collar 1 - 2017 | Short | Natural Gas
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl) | $ / MMBTU	2.35
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4
Fixed Price Swap 1 - 2017 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | MMBTU	1,500	[1]
Total of Notional Volume (MMBtu) | MMBTU	321,000	[1]
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU	3.30	[1]
Costless Collar 1 - 2017 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | MMBTU	2,000	[2]
Total of Notional Volume (MMBtu) | MMBTU	180,000	[2]
Costless Collar 1 - 2017 | Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3.10	[2]
Costless Collar 1 - 2017 | Short | Natural Gas
Derivative [Line Items]
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	3.78	[2]
Costless Three-way Collar 1 - 2018 | Natural Gas
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | MMBTU	5,000
Total of Notional Volume (MMBtu) | MMBTU	1,825,000
Costless Three-way Collar 1 - 2018 | Long | Natural Gas
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU	3
Costless Three-way Collar 1 - 2018 | Short | Natural Gas
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl) | $ / MMBTU	2.35
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU	4
Crude Oil | Costless Three-way Collar 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	280	[3]
Total of Notional Volume (Bbl) | bbl	102,200
Crude Oil | Costless Three-way Collar 1 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	80
Crude Oil | Costless Three-way Collar 1 - 2017 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	65
Ceiling (Short) (Price per MMBtu or Bbl)	97.25
Crude Oil | Costless Three-way Collar 2 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	250	[3]
Total of Notional Volume (Bbl) | bbl	91,250
Crude Oil | Costless Three-way Collar 2 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	80
Crude Oil | Costless Three-way Collar 2 - 2017 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	60
Ceiling (Short) (Price per MMBtu or Bbl)	98.70
Crude Oil | Protective Spread 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	200	[3],[4]
Total of Notional Volume (Bbl) | bbl	36,200	[4]
Base Fixed Price (Price per MMBtu or Bbl)	60	[4]
Crude Oil | Protective Spread 1 - 2017 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	42.50	[4]
Crude Oil | Put Spread - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	500	[3]
Total of Notional Volume (Bbl) | bbl	182,500
Crude Oil | Put Spread - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	82
Crude Oil | Put Spread - 2017 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	62
Crude Oil | Protective Spread 2 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	200	[3],[4]
Total of Notional Volume (Bbl) | bbl	36,200	[4]
Base Fixed Price (Price per MMBtu or Bbl)	57.50	[4]
Crude Oil | Protective Spread 2 - 2017 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	42.50	[4]
Crude Oil | Fixed Price Swap 1 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	300	[3],[4]
Total of Notional Volume (Bbl) | bbl	54,300	[4]
Base Fixed Price (Price per MMBtu or Bbl)	50.10	[4]
Crude Oil | Costless Three-way Collar 3 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	200	[3],[5]
Total of Notional Volume (Bbl) | bbl	36,800	[5]
Crude Oil | Costless Three-way Collar 3 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	60	[5]
Crude Oil | Costless Three-way Collar 3 - 2017 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	42.50	[5]
Ceiling (Short) (Price per MMBtu or Bbl)	85	[5]
Crude Oil | Costless Three-way Collar 4 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	200	[3],[5]
Total of Notional Volume (Bbl) | bbl	36,800	[5]
Crude Oil | Costless Three-way Collar 4 - 2017 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	57.50	[5]
Crude Oil | Costless Three-way Collar 4 - 2017 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	42.50	[5]
Ceiling (Short) (Price per MMBtu or Bbl)	76.13	[5]
Crude Oil | Fixed Price Swap 2 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	200	[2],[3]
Total of Notional Volume (Bbl) | bbl	18,000	[2]
Base Fixed Price (Price per MMBtu or Bbl)	50.05	[2]
Crude Oil | Fixed Price Swap 3 - 2017
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	275	[3],[4]
Total of Notional Volume (Bbl) | bbl	49,775	[4]
Base Fixed Price (Price per MMBtu or Bbl)	51.25	[4]
Crude Oil | Put Spread - 2018
Derivative [Line Items]
Average Daily Volume (MMBtu or Bbl) | bbl	425	[3],[6]
Total of Notional Volume (Bbl) | bbl	103,275	[6]
Crude Oil | Put Spread - 2018 | Long
Derivative [Line Items]
Floor (Long) (Price per MMBtu or Bbl)	80	[6]
Crude Oil | Put Spread - 2018 | Short
Derivative [Line Items]
Put (Short) (Price per MMBtu or Bbl)	60	[6]
[1]	For the period April to October 2017.
[2]	For the period January to March 2017.
[3]	Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production.
[4]	For the period January to June 2017.
[5]	For the period July to December 2017.
[6]	For the period January to August 2018.

Derivative Instruments and He61

Derivative Instruments and Hedging Activity (Summary of Information Regarding Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Current commodity derivative premium put payable			$ 1,654	$ 3,194
Long-term commodity derivative premium payable			969	2,788
Total unamortized put premium liabilities	$ 2,623	$ 5,982	$ 2,623	$ 5,982
Put Premium Liabilities [Roll Forward]
Put premium liabilities, beginning balance	5,982	7,183
Settlement of put premium liabilities	(3,194)	(2,295)
Additional put premium liabilities	(165)	1,094
Put premium liabilities, ending balance	$ 2,623	$ 5,982

Derivative Instruments and He62

Derivative Instruments and Hedging Activity (Summary of Amortization of Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
January to December 2017	$ 1,654
January to December 2018	969
Total unamortized put premium liabilities	$ 2,623	$ 5,982	$ 7,183

Derivative Instruments and He63

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	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
(Loss) gain on commodity derivatives contracts	$ (2,863)	$ 24,589	$ 19,569
Commodity Contract
Derivatives, Fair Value [Line Items]
(Loss) gain on commodity derivatives contracts	(2,863)	24,589	19,569
Commodity Contract | (Loss) gain on commodity derivatives contracts
Derivatives, Fair Value [Line Items]
(Loss) gain on commodity derivatives contracts	(2,863)	24,589	$ 19,569
Commodity Contract | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Total derivatives not designated as hedging instruments	7,512	24,418
Commodity Contract | Current assets | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	6,212	15,534
Commodity Contract | Other assets | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Assets	1,638	9,335
Commodity Contract | Current liabilities | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	(338)	0
Commodity Contract | Long-term liabilities | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Commodity derivative contracts, Liabilities	$ 0	$ (451)

Capital Stock (Narrative) (Deta

Capital Stock (Narrative) (Details)

Feb. 16, 2017USD ($)$ / sharesshares

Feb. 15, 2017$ / shares

Jan. 27, 2017Right$ / shares

May 12, 2016USD ($)$ / sharesshares

Jan. 18, 2016Right$ / shares

Sep. 24, 2014USD ($)$ / sharesshares

Feb. 20, 2017USD ($)shares

Dec. 31, 2016USD ($)$ / sharesshares

Dec. 31, 2015USD ($)$ / sharesshares

Dec. 31, 2014USD ($)shares

Jan. 31, 2017shares

Jan. 10, 2017USD ($)

Jul. 05, 2016shares

May 07, 2015USD ($)

Class Of Stock [Line Items]

Proceeds from issuance of common stock, net of issuance costs | $

$ 69,224,000

$ 0

$ 101,319,000

Aggregate offering price | $

$ 50,000,000

Common stock, shares authorized

550,000,000

275,000,000

550,000,000

Aggregate principal amount | $

$ 325,000,000

$ 325,000,000

Common stock, par value | $ / shares

$ 0.001

$ 0.001

Common stock, shares issued

150,377,870

80,024,218

Common stock, shares outstanding

150,377,870

80,024,218

Dividend rights description

The Rights generally become exercisable on the earlier of (i) ten business days after any person or group obtains beneficial ownership of 4.95% of the Company’s outstanding common stock (an “Acquiring Person”) or (ii) ten business days after commencement of a tender or exchange offer resulting in any person or group becoming an Acquiring Person.

Exercise price description

In the event that, after a person or a group has become an Acquiring Person, the Company is acquired in a merger or other business combination transaction (or 50% or more of the Company’s assets or earning power are sold), proper provision will be made so that each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then-current exercise price of the Right, that number of shares of common stock of the acquiring company having a market value at the time of that transaction equal to two times the exercise price.

Percent of ownership in outstanding common stock

4.95%

Rights redemption price per right | $ / shares

$ 0.001

Rights exchange description

At any time after any person or group becomes an Acquiring Person, the Company may generally exchange each Right in whole or in part at an exchange ratio of two shares of common stock per outstanding Right, subject to adjustment.

Rights earliest expiration date

Jan. 27, 2020

Right exchange ratio for common shares

200.00%

Preferred stock, shares authorized

40,000,000

40,000,000

Dividends on preferred stock | $

$ 3,618,000

$ 14,473,000

14,424,000

Stock options

Class Of Stock [Line Items]

Common shares reserved for future issuance

214,600

PBUs

Class Of Stock [Line Items]

Common shares reserved for future issuance

1,475,730

Series A Preferred Stock

Class Of Stock [Line Items]

Preferred stock, shares authorized

10,000,000

10,000,000

Preferred stock, dividend rate, percentage (percentage)

8.625%

Preferred stock, par value | $ / shares

$ 0.01

$ 0.01

Redemption price | $ / shares

$ 25

$ 25

Preferred stock, shares issued

4,045,000

4,045,000

Preferred stock, shares outstanding

4,045,000

4,045,000

Fixed rate preferred dividend increases percentage if suspension more than one year

2.00%

Dividends on preferred stock | $

$ 8,700,000

$ 8,700,000

8,700,000

Accumulated and unpaid dividends on preferred stock transferred to liquidation preference | $

$ 6,500,000

Accumulated and unpaid dividends on preferred stock transferred to liquidation preference per share | $ / shares

$ 1.6171875

Series B Preferred Stock

Class Of Stock [Line Items]

Preferred stock, shares authorized

10,000,000

10,000,000

Preferred stock, dividend rate, percentage (percentage)

10.75%

Preferred stock, par value | $ / shares

$ 0.01

$ 0.01

Redemption price | $ / shares

$ 25

$ 25

Preferred stock, shares issued

2,140,000

2,140,000

Preferred stock, shares outstanding

2,140,000

2,140,000

Fixed rate preferred dividend increases percentage if suspension more than one year

2.00%

Dividends on preferred stock | $

$ 5,800,000

$ 5,800,000

$ 5,800,000

Accumulated and unpaid dividends on preferred stock transferred to liquidation preference | $

$ 4,300,000

Accumulated and unpaid dividends on preferred stock transferred to liquidation preference per share | $ / shares

$ 2.0158686

Preferred stock redemption price per share | $ / shares

$ 25

Period after change in control to redeem preferred stock

90 days

Option to convert shares of Series B Preferred Stock | $ / shares

$ 11.5207

Amendment No. 10 | Series A Preferred Stock

Class Of Stock [Line Items]

Dividends payable record date

Jan. 20, 2017

Dividends payable, date declared

Jan. 10, 2017

Dividends payable date

Jan. 31, 2017

Condition on payment of dividends

The Company’s Revolving Credit Facility, payment of the declared Series A Preferred Stock January 2017 dividend and monthly preferred stock cash dividends through May 2017 are permitted contingent upon the satisfaction of certain conditions, including but not limited to, (i) the absences of any defaults or borrowing base deficiency, (ii) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (iii) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the ATM Program).

Amendment No. 10 | Series B Preferred Stock

Class Of Stock [Line Items]

Dividends payable record date

Jan. 20, 2017

Dividends payable, date declared

Jan. 10, 2017

Dividends payable date

Jan. 31, 2017

Condition on payment of dividends

The Company’s Revolving Credit Facility, payment of the declared Series B Preferred Stock January 2017 dividend and monthly preferred stock cash dividends through May 2017 are permitted contingent upon the satisfaction of certain conditions, including but not limited to, (i) the absences of any defaults or borrowing base deficiency, (ii) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (iii) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the ATM Program).

Common Stock

Class Of Stock [Line Items]

Issuance of common shares - cash, net of offering costs (shares)

50,000,000

17,000,000

2016 Rights Agreement | Series C Preferred Stock

Class Of Stock [Line Items]

Number of rights issued on dividend declared | Right

1

Dividend payment terms

The dividend was paid to stockholders of record on January 28, 2016. Each right entitled the holder, subject to the terms of the 2016 Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Preferred Stock at a price of $6.96, subject to certain adjustments.

Preferred stock, dividend rate, per share | $ / shares

$ 6.96

Dividends payable record date

Jan. 28, 2016

Expiration date of rights

Jan. 18, 2017

2017 Rights Agreement | Series C Preferred Stock

Class Of Stock [Line Items]

Dividend payment terms

The dividend was paid to stockholders of record on February 10, 2017. Each Right entitles the registered holder, subject to the terms of the 2017 Rights Agreement to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $10.74, subject to certain adjustments.

Subsequent Events

Class Of Stock [Line Items]

Volume-weighted average trading price of the common shares | $ / shares

$ 1.7002

Subsequent Events | Amendment No. 10

Class Of Stock [Line Items]

Preferred dividends payment, minimum required cash liquidity | $

$ 30,000,000

Subsequent Events | Amendment No. 10 | Series A Preferred Stock

Class Of Stock [Line Items]

Preferred dividends payment, minimum required cash liquidity | $

30,000,000

Subsequent Events | Amendment No. 10 | Series B Preferred Stock

Class Of Stock [Line Items]

Preferred dividends payment, minimum required cash liquidity | $

$ 30,000,000

Subsequent Events | 2017 Rights Agreement | Series C Preferred Stock

Class Of Stock [Line Items]

Number of rights issued on dividend declared | Right

1

Dividend payment terms

The dividend was paid to stockholders of record on February 10, 2017. Each Right entitles the holder, subject to the terms of the 2017 Rights Agreement, to purchase one one-thousandth of a share of Series C Preferred Stock at a price of $10.74, subject to certain adjustments.

Preferred stock, dividend rate, per share | $ / shares

$ 10.74

Dividends payable record date

Feb. 10, 2017

Subsequent Events | Ares Management, LLC | Securities Purchase Agreement

Class Of Stock [Line Items]

Number of consecutive trading days used in volume-weighted average trading price

30 days

30 days

Volume-weighted average trading price of the common shares | $ / shares

$ 1.7002

Percentage of total issued and outstanding of common share issued to purchaser

18.80%

Common stock, shares issued

156,715,833

Common stock, shares outstanding

156,715,833

Subsequent Events | Ares Management, LLC | Securities Purchase Agreement | Convertible Notes due 2022

Class Of Stock [Line Items]

Aggregate principal amount | $

$ 125,000,000

Subsequent Events | Ares Management, LLC | Securities Purchase Agreement | Common Stock

Class Of Stock [Line Items]

Proceeds from issuance of common stock, net of issuance costs | $

$ 50,000,000

Issuance of common shares - cash, net of offering costs (shares)

29,408,305

Common stock, par value | $ / shares

$ 0.001

ATM Program

Class Of Stock [Line Items]

Proceeds from issuance of common stock, net of issuance costs | $

$ 24,400,000

Issuance of common shares - cash, net of offering costs (shares)

18,606,943

Expiration date

Feb. 24, 2017

ATM Program | Subsequent Events

Class Of Stock [Line Items]

Proceeds from issuance of common stock, net of issuance costs | $

$ 8,300,000

Issuance of common shares - cash, net of offering costs (shares)

5,447,919

Gastar Exploration USA

Class Of Stock [Line Items]

Shares of common stock in underwritten public offering

50,000,000

17,000,000

Price per share of underwritten public offering | $ / shares

$ 0.95

$ 6.25

Sales price of underwritten public offering before offering costs and expenses | $

$ 47,500,000

$ 106,300,000

Proceeds from issuance of common stock, net of issuance costs | $

44,800,000

101,300,000

Estimated offering costs and expenses | $

$ 2,700,000

$ 5,000,000

Capital Stock (Schedule of Issu

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details) - shares		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock issued pursuant to PBUs vested, net of forfeitures of 207,891 shares and 212,858 shares, respectively		502,593	497,636
Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of restricted common stock granted		1,764,645	1,426,604
Shares of restricted common stock vested		1,487,269	1,422,670
Shares of restricted common stock surrendered upon vesting/exercise	[1]	392,094	413,333
Shares of restricted common stock forfeited		128,435	119,499
[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.

Capital Stock (Schedule of Is66

Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Parenthetical) (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
PBUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeiture of common stock issued pursuant to PBUs vested	207,891	212,858

Equity Compensation Plans (Narr

Equity Compensation Plans (Narrative) (Details) - USD ($)	Apr. 24, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized expense for outstanding awards		$ 2,700,000
Stock-based compensation expense		$ 3,900,000	$ 5,000,000	$ 4,900,000
Unvested restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)		3 years
Unrecognized expense for outstanding awards		$ 1,100,000
Stock-based compensation expense		$ 2,700,000
Weighted average period for recognition for unrecognized expense		1 year 3 months 29 days
Unvested restricted shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)		1 year
Unvested restricted shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)		3 years
Unvested restricted shares | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)		1 year
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted		0	0	0
Unrecognized expense for outstanding awards		$ 0
PBUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		$ 1,200,000
Weighted average period for recognition for unrecognized expense		1 year 7 months 24 days
Total unrecognized expense for PBUs		$ 1,600,000
2006 Long-Term Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance under LTIP	3,000,000
Shares available for future issuance (no more than) (shares)		1,590,327
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)		1 year
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)		3 years
2006 Long-Term Stock Incentive Plan | PBUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)				3 years
Percentage settlement of targeted number of PBUs		100.00%
2006 Long-Term Stock Incentive Plan | PBUs | Cliff Vest
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting term (years)		3 years	3 years
2006 Long-Term Stock Incentive Plan | PBUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage settlement of targeted number of PBUs		0.00%
2006 Long-Term Stock Incentive Plan | PBUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage settlement of targeted number of PBUs		200.00%

Equity Compensation Plans (Shar

Equity Compensation Plans (Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable) (Details) - Stock options - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at beginning of period	866,600
Granted	0	0	0
Exercised	0
Canceled/Expired	(571,000)
Forfeited	(81,000)
Outstanding at end of period	214,600	866,600
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Weighted-Average Exercise Price, Outstanding at beginning of period	$ 11.75
Granted	0
Exercised	0
Canceled/Expired	14.77
Forfeited	8.75
Weighted-Average Exercise Price, Outstanding at end of period	$ 4.87	$ 11.75
Number of shares vested and exercisable	214,600
Weighted Average Exercise Price per Share	$ 4.87
Weighted Average Remaining Contractual Term (in years)	1 year 11 months 23 days
Aggregate Intrinsic Value	$ 0

Equity Compensation Plans (Rest

Equity Compensation Plans (Restricted Stock Activity) (Details) - Unvested restricted shares $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested PBUs at December 31, 2015 | shares	2,296,349
Granted | shares	1,764,645
Vested | shares	(1,487,269)
Forfeited | shares	(128,435)
Unvested PBUs at December 31, 2016 | shares	2,445,290
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted-Average Grant Date Fair Value, Outstanding at beginning of period | $ / shares	$ 2.63
Granted | $ / shares	1.19
Vested | $ / shares	2.37
Forfeited | $ / shares	1.88
Weighted-Average Grant Date Fair Value, Outstanding at end of period | $ / shares	$ 1.79
Weighted Average Remaining Contractual Term (in years)	1 year 5 months 27 days
Aggregate Intrinsic Value | $	$ 3,790

Equity Compensation Plans (Sche

Equity Compensation Plans (Schedule of Weighted Average Grant Date Fair Value) (Details) - Unvested restricted shares - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value (in dollars per share)	$ 1.19	$ 2.40	$ 5.85
Grant date fair value of stock options vested	$ 3,530	$ 3,794	$ 3,497

Equity Compensation Plans (Summ

Equity Compensation Plans (Summary of PBUs) (Details) - PBUs	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested PBUs at December 31, 2015 | shares	1,283,167
Granted | shares	801,397
Vested | shares	(448,634)
Forfeited | shares	(160,200)
Unvested PBUs at December 31, 2016 | shares	1,475,730
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Unvested PBUs at December 31, 2015 | $ / shares	$ 3.24
Granted | $ / shares	1.62
Vested | $ / shares	2.76
Forfeited | $ / shares	3.40
Unvested PBUs at December 31, 2016 | $ / shares	$ 2.49

Equity Compensation Plans (Sc72

Equity Compensation Plans (Schedule of Future Amortization of Unrecognized Compensation Cost) (Details) $ in Thousands	Dec. 31, 2016USD ($)
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
2,017	$ 1,913
2,018	717
2,019	56
Total	$ 2,686

Interest Expense (Schedule of C

Interest Expense (Schedule of Components of Interest Expense) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest Expense [Abstract]
Cash and accrued		$ 33,368	$ 30,981	$ 28,851
Amortization of deferred financing costs	[1]	4,980	3,584	3,067
Capitalized interest		(3,102)	(3,879)	(4,347)
Total interest expense		$ 35,246	$ 30,686	$ 27,571
[1]	The years ended December 31, 2016, 2015 and 2014 include $2.8 million, $2.5 million and $2.3 million, respectively, of debt discount accretion related to the Notes.

Interest Expense (Schedule of74

Interest Expense (Schedule of Components of Interest Expense) (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest Expense [Abstract]
Accretion of debt discount	$ 2.8	$ 2.5	$ 2.3

Income Taxes (Schedule of (Loss

Income Taxes (Schedule of (Loss) Income before Income Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
United States	$ (89,061)	$ (459,507)	$ 50,953
Total income (loss) before income taxes	$ (89,061)	$ (459,507)	$ 50,953

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Current provision for income taxes	$ 0	$ 0	$ 0
Deferred income tax expense (benefit)	0	0	$ 0
Foreign tax credit carry forwards	$ 50,681,000	$ 50,681,000
US
Operating Loss Carryforwards [Line Items]
Federal statutory rate	35.00%
Net operating loss carryforwards	$ 536,200,000

Income Taxes (Schedule of Effec

Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Expected income tax provision (benefit) at statutory rate	$ (31,172)	$ (160,827)	$ 17,833
State tax, tax effected	(1,408)	(7,799)	803
Stock-based compensation expense (benefit)	1,995	255	(1,291)
Non-deductible compensation	178	0	0
Other	693	17	38
Other changes in valuation allowance	29,714	168,354	(17,383)
Actual income tax provision	$ 0	$ 0	$ 0

Income Taxes (Schedule of Defer

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax asset (liability):
Capital assets	$ 33,131	$ 10,485
Stock-based compensation	2,499	4,243
Net operating loss carry forwards	196,775	187,963
Foreign tax credit carry forwards	50,681	50,681
Valuation allowance	(283,086)	(253,372)
Net deferred tax asset	$ 0	$ 0

Earnings per Share (Schedule of

Earnings per Share (Schedule of Earnings per Share, Basic and Diluted, by Common Class, Including Two Class Method) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 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	$ (8,163)	$ (3,796)	$ (18,100)	$ (73,475)	$ (161,143)	$ (191,819)	$ (118,014)	$ (3,004)	$ (103,534)	$ (473,980)	$ 36,529
Weighted average shares of common stock outstanding basic (shares)	132,936,419	129,301,817	104,009,337	78,788,133	77,685,049	77,628,120	77,611,167	77,114,826	111,367,452	77,511,677	63,270,733
Incremental shares from unvested restricted shares									0	0	2,451,903
Incremental shares from outstanding stock options									0	0	97,491
Incremental shares from outstanding PBUs									0	0	672,462
Weighted average shares of common stock outstanding diluted (shares)	132,936,419	129,301,817	104,009,337	78,788,133	77,685,049	77,628,120	77,611,167	77,114,826	111,367,452	77,511,677	66,492,589
Basic (dollars per share)	$ (0.06)	$ (0.03)	$ (0.17)	$ (0.93)	$ (2.07)	$ (2.47)	$ (1.52)	$ (0.04)	$ (0.93)	$ (6.11)	$ 0.58
Diluted (dollars per share)	$ (0.06)	$ (0.03)	$ (0.17)	$ (0.93)	$ (2.07)	$ (2.47)	$ (1.52)	$ (0.04)	$ (0.93)	$ (6.11)	$ 0.55
Common shares excluded from denominator as anti-dilutive (shares)									926,943	195,252	34,058
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)									438,948	177,663	34,058
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)									487,995	17,589	0

Commitments and Contingencies80

Commitments and Contingencies (Narrative) (Details)	Aug. 10, 2016USD ($)	May 03, 2016Officer	Jun. 17, 2014USD ($)	Dec. 17, 2010USD ($)	Dec. 31, 2010	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 29, 2015USD ($)	Dec. 31, 2013USD ($)	Aug. 07, 2013USD ($)
Loss Contingencies [Line Items]
Office lease expense						$ 524,000	$ 687,000	$ 649,000
Fair market value, discounted present rate						10.00%
Asset retirement obligation						$ 5,532,000	6,086,000	$ 5,557,000		$ 6,063,000
Asset retirement obligation, current						89,000	89,000
Asset retirement obligation, non-current						5,443,000	$ 5,997,000
SEI Energy LLC
Loss Contingencies [Line Items]
Contractual Obligation						$ 0
Investor | Development Agreement
Loss Contingencies [Line Items]
Fair market value, discounted present rate						15.00%
Gastar Exploration USA | SEI Energy LLC | Capacity
Loss Contingencies [Line Items]
Natural gas production term (years)					5 years
Torchlight Energy Resources, Inc., Torchlight Energy, Inc. v. Husky Ventures, Inc.
Loss Contingencies [Line Items]
Number of executive officers filed lawsuit | Officer		2
Gastar Exploration Ltd vs US Specialty Ins Co and Axis Ins Co
Loss Contingencies [Line Items]
Settlement aggregate amount	$ 10,100,000			$ 21,200,000
Directors and officers liability coverage limit				$ 20,000,000
Gastar Exploration U S A Inc V Williams Ohio Valley Midstream L L C | Gastar Exploration USA
Loss Contingencies [Line Items]
Settlement aggregate amount			$ 8,600,000
Damages sought in arbitration matter											$ 612,000
Maximum
Loss Contingencies [Line Items]
Lease Expiration Date						2022-04
Maximum | Gastar Exploration Inc V Christopher Mc Arthur
Loss Contingencies [Line Items]
Damages sought in arbitration matter									$ 2,750,000

Commitments and Contingencies81

Commitments and Contingencies (Schedule of Future Minimum Rental Commitments) (Details) $ in Thousands	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 447
2,018	733
2,019	617
2,020	620
2021 and thereafter	834
Total	$ 3,251

Concentration of Risk and Sig82

Concentration of Risk and Significant Customers (Schedule of Concentration Risk) (Details) - Natural gas, oil and NGLs revenues excluding realized hedge impact		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Customer Concentration Risk | Sunoco
Concentration Risk [Line Items]
Concentration risk, percentage		67.00%	62.00%	37.00%
Customer Concentration Risk | Superior
Concentration Risk [Line Items]
Concentration risk, percentage		12.00%	6.00%	5.00%
Customer Concentration Risk | SEI
Concentration Risk [Line Items]
Concentration risk, percentage	[1]	5.00%	22.00%	50.00%
Appalachian Basin | Geographic Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage		5.00%	17.00%	39.00%
Mid-Continent | Geographic Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage		95.00%	83.00%	61.00%
[1]	SEI filed for Chapter 7 bankruptcy on June 3, 2016.

Statement of Cash Flows - Sup83

Statement of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of capitalized amounts	$ 30,480	$ 26,859	$ 24,632
Non-cash transactions:
Capital expenditures (excluded from) included in accounts payable and accrued drilling costs	(82)	(26,228)	12,777
Capital expenditures included in accounts receivable	409		4,077
Asset retirement obligation included in oil and natural gas properties	432	526	221
Asset retirement obligation for property disposals	(1,045)	(416)	(645)
Application of advances to operators	$ (347)	11,445	58,326
Other		$ 5	$ (11)

Quarterly Consolidated Financ84

Quarterly Consolidated Financial Data - Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 18,287		$ 13,003		$ 12,153		$ 14,811		$ 22,608		$ 28,386		$ 21,928		$ 34,372
Income (loss) from operations	3,929	[1]	7,959	[1]	(5,142)	[1]	(60,592)	[1]	(149,272)	[2]	(180,272)	[2]	(107,462)	[2]	8,172	[2]	$ (53,846)	$ (428,834)	$ 78,512
Income (loss) before provision for income taxes	(4,545)		(178)		(14,481)		(69,857)		(157,525)		(188,201)		(114,395)		614
Net income (loss)	(4,545)		(178)		(14,481)		(69,857)		(157,525)		(188,201)		(114,395)		614		(89,061)	(459,507)	50,953
Dividends on preferred stock	3,618		3,618		3,619		3,618		3,618		3,618		3,619		3,618
Net loss attributable to common stockholders	$ (8,163)		$ (3,796)		$ (18,100)		$ (73,475)		$ (161,143)		$ (191,819)		$ (118,014)		$ (3,004)		$ (103,534)	$ (473,980)	$ 36,529
Net loss per share of common stock attributable to common stockholders:
Basic (in dollars per share)	$ (0.06)		$ (0.03)		$ (0.17)		$ (0.93)		$ (2.07)		$ (2.47)		$ (1.52)		$ (0.04)		$ (0.93)	$ (6.11)	$ 0.58
Diluted (in dollars per share)	$ (0.06)		$ (0.03)		$ (0.17)		$ (0.93)		$ (2.07)		$ (2.47)		$ (1.52)		$ (0.04)		$ (0.93)	$ (6.11)	$ 0.55
Weighted average shares of common stock outstanding:
Basic (shares)	132,936,419		129,301,817		104,009,337		78,788,133		77,685,049		77,628,120		77,611,167		77,114,826		111,367,452	77,511,677	63,270,733
Diluted (shares)	132,936,419		129,301,817		104,009,337		78,788,133		77,685,049		77,628,120		77,611,167		77,114,826		111,367,452	77,511,677	66,492,589
[1]	(Loss) income from operations for the first quarter includes impairment of oil and natural gas properties of $48.5 million the third quarter income from operations includes $10.1 million of litigation settlement benefit.
[2]	Income (loss) from operations for the second, third and fourth quarters include impairment of oil and natural gas properties of $100.2 million, $182.0 million and $144.8 million, respectively.

Quarterly Consolidated Financ85

Quarterly Consolidated Financial Data - Unaudited (Parenthetical) (Details) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Sep. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Impairment of natural gas and oil properties		$ 48,497	$ 144,760	$ 181,966	$ 100,152	$ 48,497	$ 426,878	$ 0
Litigation settlement benefit	$ 10,100					$ 10,100	$ 0	$ 0

Supplemental Oil and Gas Disc86

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	$ 1,253,061	$ 1,286,373
Unproved properties	67,333	92,609
Total natural gas and oil properties	1,320,394	1,378,982
Impairment of proved oil and natural gas properties	(813,314)	(764,817)
U S
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	1,253,061	1,286,373	$ 1,124,367
Unproved properties	67,333	92,609	128,274
Total natural gas and oil properties	1,320,394	1,378,982	1,252,641
Impairment of proved oil and natural gas properties	(813,314)	(764,817)	(337,939)
Accumulated depreciation, depletion and amortization	(315,373)	(286,020)	(223,555)
Net capitalized costs	$ 191,707	$ 328,145	$ 691,147

Supplemental Oil and Gas Disc87

Supplemental Oil and Gas Disclosures - Unaudited (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Asset retirement costs	$ 1.5	$ 2.4	$ 2.4

Supplemental Oil and Gas Disc88

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Proved property acquisition	$ 570	$ 15,615	$ 0
Unproved property acquisition	38,941	50,434	41,475
Exploration	19,761	53,290	127,384
Development	3,810	54,316	57,913
Total costs incurred	$ 63,082	$ 173,655	$ 226,772

Supplemental Oil and Gas Disc89

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Results of Operations for Oil and Gas Producing Activities) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / MBoe	Dec. 31, 2015USD ($)$ / MBoe	Dec. 31, 2014USD ($)$ / MBoe
Extractive Industries [Abstract]
Oil, condensate, natural gas and NGLs sales, including commodity derivatives	$ 58,254	$ 107,294	$ 171,418
Production expenses	(24,217)	(28,792)	(29,735)
Impairment of oil and natural gas properties	(48,497)	(426,878)	0
Depreciation, depletion and amortization	(29,353)	(62,465)	(45,765)
Results of producing activities	$ (43,813)	$ (410,841)	$ 95,918
Depreciation, depletion and amortization per MBoe | $ / MBoe	10.23	12.67	12.34

Supplemental Oil and Gas Disc90

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Oil and Gas Net Production, Average Sales Price and Average Production Costs) (Details)		3 Months Ended												12 Months Ended
		Dec. 31, 2016$ / MMBTU$ / bbl	Sep. 30, 2016$ / MMBTU$ / bbl	Jun. 30, 2016$ / MMBTU$ / bbl	Mar. 31, 2016$ / MMBTU$ / bbl	Dec. 31, 2015$ / MMBTU$ / bbl	Sep. 30, 2015$ / MMBTU$ / bbl	Jun. 30, 2015$ / MMBTU$ / bbl	Mar. 31, 2015$ / MMBTU$ / bbl	Dec. 31, 2014$ / MMBTU$ / bbl	Sep. 30, 2014$ / MMBTU$ / bbl	Jun. 30, 2014$ / MMBTU$ / bbl	Mar. 31, 2014$ / MMBTU$ / bbl	Dec. 31, 2016$ / MMBTU$ / bbl	Dec. 31, 2015$ / MMBTU$ / bbl	Dec. 31, 2014$ / MMBTU$ / bbl
Natural gas (per MMBtu):
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Key natural gas and oil prices | $ / MMBTU	[1]	2.48	2.28	2.24	2.40	2.59	3.06	3.39	3.88	4.35	4.24	4.10	3.99
Oil (per Bbl):
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Key natural gas and oil prices | $ / bbl	[1]	42.75	41.68	43.12	46.26	50.28	59.21	71.68	82.72	94.99	99.08	100.11	98.30
Henry Hub | Natural gas (per MMBtu):
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Key natural gas and oil prices | $ / MMBTU														2.48	2.59	4.35
WTI spot | Oil (per Bbl):
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Key natural gas and oil prices | $ / bbl														42.75	50.28	94.99
[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.

Supplemental Oil and Gas Disc91

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) bbl in Thousands, MBoe in Thousands		12 Months Ended
		Dec. 31, 2016MBoebblMMcf		Dec. 31, 2015MBoebblMMcf		Dec. 31, 2014MBoebblMMcf
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period, equivalents | MBoe	[1]	55,877		102,063		54,634
Extensions and discoveries | MBoe	[1]	3,681		9,374	[2]	42,810	[3]
Revisions of previous estimates | MBoe	[1]	(16,177)	[4]	(53,268)	[5]	8,574
Production | MBoe	[1]	(2,869)		(4,931)		(3,708)
Purchases in place | MBoe	[1]			2,971
Sales in place | MBoe	[1]	(14,935)		(332)		(247)
Proved reserves at the end of the period. equivalents | MBoe	[1]	25,577		55,877		102,063
Proved developed reserves | MBoe	[1]	13,015		28,415		36,789
Proved undeveloped reserves | MBoe	[1]	12,562		27,462		65,274
Total | MBoe	[1]	25,577		55,877		102,063
Oil
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period	[6]	24,202		28,636		14,718
Extensions and discoveries	[6]	1,582		4,777	[2]	13,137	[3]
Revisions of previous estimates	[6]	(9,890)	[4]	(8,962)	[5]	1,780
Production	[6]	(1,105)		(1,425)		(975)
Purchases in place	[6]			1,270
Sales in place	[6]	(1,033)		(94)		(24)
Proved reserves as of the end of the period	[6]	13,756		24,202		28,636
Proved developed reserves	[6]	6,037		7,181		6,968
Proved undeveloped reserves	[6]	7,719		17,021		21,668
Total	[6]	13,756		24,202		28,636
Natural Gas
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period | MMcf	[7]	108,451		287,005		180,710
Extensions and discoveries | MMcf	[7]	7,213		14,114	[2]	121,672	[3]
Revisions of previous estimates | MMcf	[7]	(17,825)	[4]	(182,600)	[5]	(2,465)
Production | MMcf	[7]	(6,145)		(13,759)		(11,598)
Purchases in place | MMcf	[7]			4,965
Sales in place | MMcf	[7]	(53,841)		(1,274)		(1,314)
Proved reserves as of the end of the period | MMcf	[7]	37,853		108,451		287,005
Proved developed reserves | MMcf	[8]	22,786		77,966		114,564
Proved undeveloped reserves | MMcf	[8]	15,067		30,485		172,441
Total | MMcf	[8]	37,853		108,451		287,005
Natural Gas Liquids
Proved Developed And Undeveloped Reserves [Roll Forward]
Proved reserves as of the beginning of the period	[6]	13,599		25,593		9,798
Extensions and discoveries	[6]	898		2,244	[2]	9,394	[3]
Revisions of previous estimates	[6]	(3,317)	[4]	(13,873)	[5]	7,205
Production	[6]	(739)		(1,212)		(800)
Purchases in place	[6]			873
Sales in place	[6]	(4,929)		(26)		(4)
Proved reserves as of the end of the period	[6]	5,512		13,599		25,593
Proved developed reserves	[6]	3,181		8,240		10,726
Proved undeveloped reserves	[6]	2,332		5,359		14,867
Total	[6]	5,512		13,599		25,593
[1]	Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
[2]	All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations.
[3]	Of the 2014 extensions and discoveries, 69% resulted from successful drilling results in the Marcellus Shale. The remainder of the 2014 extensions and discoveries resulted from the Company's Mid-Continent drilling operations.
[4]	The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position.
[5]	The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014.
[6]	Thousand barrels
[7]	Million cubic feet or million cubic feet equivalent, as applicable
[8]	Million cubic feet

Supplemental Oil and Gas Disc92

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Parenthetical) (Details) - MBoe MBoe in Thousands		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Reserve Quantities [Line Items]
Production, Barrels of Oil Equivalents		Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
Percentage of extensions and discoveries from successful drilling results in Marcellus Shale						69.00%
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease)	[2]	16,177	[1]	53,268	[3]	(8,574)
Appalachian Basin
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease)				(36,800)
[1]	The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position.
[2]	Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas.
[3]	The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014.

Supplemental Oil and Gas Disc93

Supplemental Oil and Gas Disclosures - Unaudited (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves) (Details) - U S - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 710,370	$ 1,425,734	$ 3,855,227
Future production costs	(328,010)	(547,484)	(1,048,554)
Future development costs	(123,214)	(365,123)	(611,602)
Future income taxes			(486,593)
Future net cash flows	259,146	513,127	1,708,478
10% annual discount for estimated timing of cash flows	(117,815)	(283,324)	(891,739)
Standardized measure of discounted future cash flows	$ 141,331	$ 229,803	$ 816,739	$ 515,829

Supplemental Oil and Gas Disc94

Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) - U S - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Beginning of period	$ 229,803	$ 816,739	$ 515,829
Extensions and discoveries, less related costs	19,270	71,547	369,806
Sale of natural gas and oil, net of production costs	(36,900)	(53,914)	(122,114)
Sales of reserves in place	(16,023)	(4,853)	(1,475)
Purchases of reserves in place		9,937
Revisions of previous quantity estimates	(115,785)	(324,036)	101,044
Net change in income tax		171,946	(95,245)
Net change in prices and production costs	(43,270)	(604,074)	59,786
Accretion of discount	(16,461)	98,869	(3,996)
Development costs incurred		10,500	37,461
Net change in estimated future development costs	119,531	31,131	(1,276)
Change in production rates (timing) and other	1,166	6,011	(43,081)
End of period	$ 141,331	$ 229,803	$ 816,739