Petroquest Energy (PQ) 10-K 8 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Feb. 28, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	872,248
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		25,587,441
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 38,595

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 15,655	$ 28,312
Revenue receivable	15,340	10,294
Joint interest billing receivable	6,597	7,632
Other receivable	7,750	0
Derivative asset	1,174	0
Deposit for surety bonds	8,300	0
Other current assets	2,125	2,353
Total current assets	56,941	48,591
Oil and gas properties:
Oil and gas properties, full cost method	1,369,861	1,323,333
Unevaluated oil and gas properties	21,854	9,015
Accumulated depreciation, depletion and amortization	(1,285,660)	(1,243,286)
Oil and gas properties, net	106,055	89,062
Other property and equipment	9,353	10,951
Accumulated depreciation of other property and equipment	(8,843)	(10,109)
Total property and equipment	106,565	89,904
Other assets, net of accumulated amortization of $0 and $4,385, respectively	792	6,365
Total assets	164,298	144,860
Current liabilities:
Accounts payable to vendors	36,179	25,265
Advances from co-owners	1,730	2,330
Oil and gas revenue payable	19,344	22,146
Accrued interest	1,724	2,047
Asset retirement obligation	687	4,160
Derivative liability	731	3,947
10% Senior Unsecured Notes due 2017	0	22,568
Other accrued liabilities	2,445	3,938
Total current liabilities	62,840	86,401
Multi-draw Term Loan	27,963	7,249
Asset retirement obligation	30,623	32,450
Other long-term liabilities	10,409	6,027
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares	1	1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 25,521 and 21,197 shares, respectively	26	21
Paid-in capital	313,244	304,341
Accumulated other comprehensive income (loss)	278	(4,750)
Accumulated deficit	(562,484)	(550,708)
Total stockholders’ equity	(248,935)	(251,095)
Total liabilities and stockholders’ equity	164,298	144,860
10% Senior Secured Notes due 2021 | Senior Notes
Current liabilities:
10% Senior Secured Notes	9,821	15,228
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Current liabilities:
10% Senior Secured Notes	$ 271,577	$ 248,600

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Accumulated depreciation and amortization	$ 0	$ 4,385
Preferred stock, par value (usd per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	1,495,000	1,495,000
Preferred stock, shares outstanding	1,495,000	1,495,000
Common stock, par value (usd per share)	$ 0.001	$ 0.001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	25,521,000	21,197,000
Common stock, shares outstanding	25,521,000	21,197,000
10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate (as a percent)	10.00%	10.00%
10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate (as a percent)	10.00%
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate (as a percent)	10.00%

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil and gas sales	$ 108,287	$ 66,667	$ 115,969
Expenses:
Lease operating expenses	33,162	28,508	40,130
Production taxes	3,302	354	2,470
Depreciation, depletion and amortization	32,053	28,720	63,497
Ceiling test write-down	0	40,304	266,562
General and administrative	15,860	26,040	20,777
Accretion of asset retirement obligation	2,252	2,515	3,259
Interest expense	28,836	30,019	33,766
Total expenses	115,465	156,460	430,461
Other income (expense):
Gain on sale of assets	0	0	21,937
Other income (expense)	(408)	(560)	391
Other income (expense), net	(408)	(560)	22,328
Loss from operations	(7,586)	(90,353)	(292,164)
Income tax expense (benefit)	(949)	543	2,626
Net loss	(6,637)	(90,896)	(294,790)
Preferred stock dividend	5,139	5,349	5,139
Net loss available to common stockholders	$ (11,776)	$ (96,245)	$ (299,929)
Basic
Net loss per share (in usd per share)	$ (0.55)	$ (5.24)	$ (18.45)
Diluted
Net loss per share (in usd per share)	$ (0.55)	$ (5.24)	$ (18.45)
Weighted average number of common shares:
Basic (shares)	21,330	18,354	16,256
Diluted (shares)	21,330	18,354	16,256

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Loss - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (6,637)	$ (90,896)	$ (294,790)
Change in fair value of derivatives, net of income tax (expense) benefit of ($165), $561 and $2,650, respectively	5,028	(5,697)	(4,473)
Comprehensive loss	$ (1,609)	$ (96,593)	$ (299,263)

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Loss (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Income tax (expense) benefit related to other comprehensive income due to derivatives	$ (165)	$ 561	$ 2,650

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows provided by (used in) operating activities:
Net loss	$ (6,637)	$ (90,896)	$ (294,790)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred tax (benefit) expense	(949)	543	2,626
Depreciation, depletion and amortization	32,053	28,720	63,497
Ceiling test write-down	0	40,304	266,562
Accretion of asset retirement obligation	2,252	2,515	3,259
Share based compensation expense	1,447	1,444	4,617
Gain on sale of assets	0	0	(21,937)
Amortization costs and other	554	2,106	2,259
Non-cash PIK interest	22,895	5,722	0
Payments to settle asset retirement obligations	(3,364)	(3,169)	(2,776)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	0	10,139	0
Gain on extinguishment of debt	(403)	0	0
Changes in working capital accounts:
Revenue receivable	(5,046)	(3,818)	10,009
Joint interest billing receivable	610	41,400	223
Accounts payable and accrued liabilities	2,970	(72,760)	(9,400)
Advances from co-owners	(600)	(13,788)	3,299
Other	(1,629)	(5,060)	2,657
Net cash provided by (used in) operating activities	44,153	(56,598)	30,105
Cash flows (used in) provided by investing activities:
Investment in oil and gas properties	(64,613)	(30,366)	(90,218)
Investment in other property and equipment	(54)	(24)	(454)
Sale of oil and gas properties	10,707	25,482	271,769
Net cash (used in) provided by investing activities	(53,960)	(4,908)	181,097
Cash flows used in financing activities:
Net payments for share based compensation	(26)	11	(199)
Deferred financing costs	(174)	(3,156)	(1,094)
Payment of preferred stock dividend	0	(1,285)	(5,139)
Proceeds from borrowings	20,000	10,000	70,000
Repayment of borrowings	0	0	(145,000)
Redemption of 2017 Notes	(22,650)	(53,626)	0
Costs incurred to issue 2021 Notes and 2021 PIK Notes	0	(10,139)	0
Net cash used in financing activities	(2,850)	(58,195)	(81,432)
Net (decrease) increase in cash and cash equivalents	(12,657)	(119,701)	129,770
Cash and cash equivalents, beginning of period	28,312	148,013	18,243
Cash and cash equivalents, end of period	15,655	28,312	148,013
Cash paid (received) during the period for:
Interest	7,432	33,206	36,217
Income taxes	$ (94)	$ (18)	$ 0

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Preferred Stock	Paid-In Capital	Other Comprehensive Income (Loss)	Accumulated Deficit
Beginning balance at Dec. 31, 2014	$ 136,909	$ 16	$ 1	$ 286,006	$ 5,420	$ (154,534)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Options exercised	61			61
Retirement of shares upon vesting of restricted stock	(451)	0		(451)
Share-based compensation expense	4,617			4,617
Issuance of shares under employee stock purchase plan	199			199
Derivative fair value adjustment, net of tax	(4,473)				(4,473)
Preferred stock dividend	(5,139)					(5,139)
Net loss	(294,790)					(294,790)
Ending balance at Dec. 31, 2015	(163,067)	16	1	290,432	947	(454,463)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of shares in debt exchange	12,525	5		12,520
Retirement of shares upon vesting of restricted stock	(200)	0		(200)
Share-based compensation expense	1,444			1,444
Issuance of shares under employee stock purchase plan	145			145
Derivative fair value adjustment, net of tax	(5,697)				(5,697)
Preferred stock dividend	(5,349)					(5,349)
Net loss	(90,896)					(90,896)
Ending balance at Dec. 31, 2016	(251,095)	21	1	304,341	(4,750)	(550,708)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of shares	7,446	5		7,441
Retirement of shares upon vesting of restricted stock	(10)	0		(10)
Share-based compensation expense	1,447			1,447
Issuance of shares under employee stock purchase plan	25			25
Derivative fair value adjustment, net of tax	5,028				5,028
Preferred stock dividend	(5,139)					(5,139)
Net loss	(6,637)					(6,637)
Ending balance at Dec. 31, 2017	$ (248,935)	$ 26	$ 1	$ 313,244	$ 278	$ (562,484)

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Summary of Significant Accounting Policies	Organization and Summary of Significant Accounting Policies PetroQuest Energy, Inc. (a Delaware Corporation) (“PetroQuest”) is an independent oil and gas company headquartered in Lafayette, Louisiana with an exploration office in The Woodlands, Texas. It is engaged in the exploration, development, acquisition and operation of oil and gas properties in Texas and Louisiana. Principles of Consolidation The consolidated financial statements include the accounts of PetroQuest and its subsidiaries, PetroQuest Energy, L.L.C., PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC (collectively, the "Company"). All intercompany accounts and transactions have been eliminated. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserves and future net cash flows from estimated proved reserves are based on geological and engineering data and depend upon a number of variable factors and assumptions. Changes in estimated proved oil and gas reserves used in the calculation of depreciation, depletion and amortization of oil and gas properties or the present value of the estimated future net cash flows from estimated proved reserves used in the ceiling test could have a material impact on future results of operations. Oil and Gas Properties The Company utilizes the full cost method of accounting, which involves capitalizing all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves including the costs of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes the portion of general and administrative costs that can be directly identified with acquisition, exploration or development of oil and gas properties. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold, or management determines these costs to have been impaired. Interest is capitalized on unevaluated property costs. Transactions involving sales of reserves in place are recorded as adjustments to accumulated depreciation, depletion and amortization with no gain or loss recognized, unless such adjustments would cause a significant alteration in the relationship between capitalized costs and proved reserves. Depreciation, depletion and amortization of oil and gas properties is computed using the unit-of-production method based on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development costs associated therewith, are included in the depreciable base. The costs of investments in unevaluated properties are excluded from this calculation until the related properties are evaluated, proved reserves are established or the properties are determined to be impaired. Proved oil and gas reserves are estimated annually by independent petroleum engineers. The capitalized costs of proved oil and gas properties cannot exceed the present value of the estimated net future cash flows from proved reserves based on historical twelve-month, first day of the month, average oil, gas and natural gas liquid prices, including the effect of hedges in place (the full cost ceiling). If the capitalized costs of proved oil and gas properties exceed the full cost ceiling, the Company is required to write-down the value of its oil and gas properties to the full cost ceiling amount. The Company follows the provisions of Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of Accounting Standards Codification ("ASC") Topic 410-20 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test. Cash and Cash Equivalents The Company considers all highly liquid investments with a stated maturity of three months or less to be cash and cash equivalents. The majority of the Company’s cash and cash equivalents are in overnight securities made through its commercial bank accounts, which result in available funds the next business day. Accounts Receivable In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests. Other Property and Equipment The costs related to other furniture and fixtures are depreciated on a straight line basis over estimated useful lives ranging from three to five years. Deposit For Surety Bonds The deposit for surety bonds of $8.3 million at December 31, 2017 represents cash collateral paid with respect to the Company's surety bonds which secure its offshore decommissioning obligations. As a result of the sale of the Company's Gulf of Mexico assets in January 2018, the Company expects these deposits will be refunded during 2018 (subject to the Company's obligation to pay approximately $3.8 million to the purchaser of these assets). At December 31, 2016 , deposits for surety bonds totaled $6.2 million and were included in other assets in the Company's consolidated financial statements. Income Taxes The Company accounts for income taxes in accordance with ASC Topic 740. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, the Company may use certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs. Other financial and income tax reporting differences occur primarily as a result of statutory depletion. Deferred tax assets are assessed for realizability and a valuation allowance is established for any portion of the asset for which it is more likely than not will not be realized. Revenue Recognition The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. See "Recently Issued Accounting Standards" below for discussion of the adoption of the new revenue recognition standard. Concentrations The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary. The following table identifies customers from whom the Company derived 10% or more of its oil and gas revenues during the years presented. Based on the availability of other customers, the Company does not believe the loss of any of these customers would have a significant effect on its business or financial condition. Year Ended December 31, 2017 2016 2015 Superior Natural Gas 29% 14% (a) Shell Trading Company 24% 23% 18% Laclede Energy Resources (a) 17% 21% BG Group (a) 10% 10% Unimark, LLC (a) (a) 17% (a) Less than 10 percent Derivative Instruments Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is effective. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the statement of operations as derivative income (expense). The Company does not offset fair value amounts recognized for derivative instruments. The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2017 , the Company’s derivative instruments were designated as effective cash flow hedges. See Note 7 for further discussion of the Company’s derivative instruments. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods and or services. In August 2015, the FASB issued ASU 2015-14 deferring the effective date of ASU 2014-09 by one year to interim and annual periods beginning on or after December 31, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. The Company adopted the new standard effective January 1, 2018 using the modified retrospective approach. The adoption of the standard did not have a material impact on the Company's consolidated financial statements, but will result in increased disclosures related to revenue recognition policies and disaggregation of revenues. In February 2016, the FASB issued ASU 2016-02, " Leases (Topic 842), " to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. The Company is currently evaluating the effect that this new standard may have on its consolidated financial statements. In March 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation (Topic 718)," to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The Company adopted ASU 2016-09 on January 1, 2017, and the adoption of the standard did not have a material impact on the Company's consolidated financial statements. In August 2017, the FASB issued ASU 2017-12, "Derivative and Hedging," to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its consolidated financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. ASU 2017-12 is effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with earlier application permitted. The Company is currently evaluating the effect that this new standard may have on its consolidated financial statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Divestitures: On June 4, 2015 , the Company completed the sale of a majority of its interests in the Woodford Shale and Mississippian Lime for $280 million , subject to customary post-closing purchase price adjustments, effective January 1, 2015 . At closing, the Company received $257.7 million in cash and recognized a receivable of $13.9 million , which was received in full during the third quarter of 2015. At December 31, 2014, the estimated proved reserves attributable to the assets sold totaled approximately 227.2 Bcfe (unaudited), which represented approximately 57% (unaudited) of the Company's estimated proved reserves. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. A significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the sale was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of $23.2 million during 2015. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. In March 2016, the Company sold certain non-producing assets in East Texas for $7 million to a potential joint venture partner. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. After determining it would not pursue a joint venture with this party, the Company repurchased the non-producing assets for $5 million in December, 2016 as per the terms of the purchase and sale agreement. The Company subsequently entered into a new drilling joint venture in East Texas with another group of partners. On April 20, 2016 , the Company completed the sale of a majority of its remaining Woodford Shale assets in the East Hoss field for approximately $18 million , subject to customary post-closing purchase price adjustments, effective April 1, 2016 . This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. On October 31, 2016 , the Company completed the sale of its remaining Oklahoma assets for approximately $0.7 million , subject to customary post-closing purchase-price adjustments, effective November 1, 2016 . This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. On April 17, 2017 , the Company completed the sale of its interest in the East Lake Verret field in Louisiana for approximately $2.2 million . This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. On December 15, 2017 , the Company completed the sale of its saltwater disposal assets in East Texas for approximately $8.5 million . This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. Acquisitions: On December 20, 2017 , the Company entered into an oil focused play in central Louisiana targeting the Austin Chalk formation through the execution of agreements to acquire interests in approximately 24,600 gross acres for a purchase price of approximately $9.3 million and the issuance of 2.0 million shares of common stock. Subsequent Event: On January 31, 2018 , the Company sold its Gulf of Mexico properties (the "Sold Assets"). The Company received no consideration from the sale of these properties and is required to contribute approximately $3.8 million towards the future abandonment costs for the properties. As a result of the sale, the Company extinguished approximately $28.4 million of its discounted asset retirement obligation subsequent to December 31, 2017 (see Note 6). In connection with the sale, the Company expects to receive a cash refund of approximately $10.7 million related to a depositary account that served to collateralize a portion of the Company's offshore bonds related to these properties (subject to the Company's obligation to pay approximately $3.8 million to the purchaser of these properties), $8.3 million of which is included in deposits for surety bonds on the Company's Consolidated Balance Sheet as of December 31, 2017 .

Equity

Equity	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Equity	Equity Common Stock On May 18, 2016, the Company effected a reverse split of its common stock at a ratio of one share of newly issued common stock for each four shares of issued and outstanding common stock (the "Reverse Split"). The purpose of the Reverse Split was to increase the per share trading price of the Company's common stock in order to regain compliance with the New York Stock Exchange continued listing standards. The Reverse Split proportionately reduced the total number of outstanding shares of common stock from approximately 70.5 million shares to approximately 17.6 million shares. All references in the consolidated financial statements and notes to consolidated financial statements to the number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the Reverse Split. During December 2017, the Company issued 2.0 million shares of common stock in connection with the acquisition of Austin Chalk acreage. Additionally, during December 2017, the Company issued appoximately 2.2 million shares of common stock related to the extinguishment of a portion of the outstanding 2021 Notes (see Note 9). Convertible Preferred Stock The Company has 1,495,000 shares of 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) outstanding. The following is a summary of certain terms of the Series B Preferred Stock: Dividends . The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter. In connection with an amendment to the Company's bank credit facility (which was terminated and replaced by the Multidraw Term Loan Agreement with Franklin Custodian Funds in October 2016) prohibiting the Company from declaring or paying dividends on the Series B Preferred Stock, the Company suspended the quarterly cash dividend on it Series B Preferred Stock beginning with the dividend payment due on April 15, 2016. The Multidraw Term Loan Agreement also prohibits the Company from declaring and paying cash dividends on the Series B Preferred Stock. Under the terms of the Series B Preferred Stock, any unpaid dividends will accumulate. As of December 31, 2017 , the Company has deferred seven quarterly dividend payments and has accrued a $10.3 million payable related to the seven deferred quarterly dividends and the quarterly dividend that was payable on January 15, 2018, which is included in other long-term liabilities on the Consolidated Balance Sheet. As a result of the restrictions under the Multidraw Term Loan Agreement, the Company did not pay the dividend that was payable on July 15, 2017, which represented the sixth deferred dividend payment. As a result, the holders of the Series B Preferred Stock, voting as a single class, currently have the right to elect two additional directors to the Company's Board of Directors (the "Board") until all accumulated and unpaid dividends on the Series B Preferred Stock are paid in full. On August 23, 2017, the Board received written notice from two affiliated holders of the Series B Preferred Stock (the "Requesting Holders") exercising this right by requesting that the Board call a special meeting of the holders of the Preferred Stock for the purposes of electing the additional directors, as set forth in Section 4(ii) of the Certificate of Designations establishing the Preferred Stock, dated September 24, 2007. However, on October 20, 2017, as a result of discussions between the Company's management and certain holders of the Series B Preferred Stock, the Requesting Holders withdrew their request that the Board call the special meeting of the holders of the Series B Preferred Stock, and the Board determined not to call a special meeting of the holders of the Series B Preferred Stock at that time. The Company is committed to working with holders of the Series B Preferred Stock as they identify and evaluate potential candidates to add to the existing Board in 2018. Mandatory conversion . The Company may, at its option, cause shares of the Series B Preferred Stock to be automatically converted at the applicable conversion rate, but only if the closing sale price of the Company’s common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day. Conversion rights . Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into 0.8608 shares of the Company’s common stock (which is based on an initial conversion price of approximately $58.08 per share of common stock, subject to further adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver upon conversion (if any) will be based upon a 20 trading day averaging period. Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Series B Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share amounts) is as follows: For the Year Ended December 31, 2017 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (11,776 ) 21,330 $ (0.55 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (11,776 ) 21,330 $ (0.55 ) For the Year Ended December 31, 2016 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (96,245 ) 18,354 $ (5.24 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (96,245 ) 18,354 $ (5.24 ) For the Year Ended December 31, 2015 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (299,929 ) 16,256 $ (18.45 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (299,929 ) 16,256 $ (18.45 ) An aggregate of 1.6 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 1.3 million shares were not included in the computation of diluted earnings per share for the year ended December 31, 2017 , because the inclusion would have been anti-dilutive as a result of the net loss reported for the year. An aggregate of 0.9 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 1.3 million shares were not included in the computation of diluted earnings per share during the year ended December 31, 2016 , because the inclusion would have been anti-dilutive as a result of the net loss reported for the year. An aggregate of 0.1 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 1.3 million shares were not included in the computation of diluted earnings per share during the year ended December 31, 2015 , because the inclusion would have been anti-dilutive as a result of the net loss reported for the year.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	Share-Based Compensation The Company accounts for share-based compensation in accordance with ASC Topic 718. Share-based compensation cost is recognized over the requisite service period. Compensation cost for awards with graded vesting is recognized using the accelerated attribution method. Share-based compensation cost is reflected as a component of general and administrative expenses. A detail of share-based compensation cost for the years ended December 31, 2017 , 2016 and 2015 is as follows (in thousands): Year Ended December 31, 2017 2016 2015 Stock options: Incentive Stock Options (share settled) $ 820 $ 206 $ 243 Non-Qualified Stock Options (share settled) 387 164 71 Restricted stock (share settled) 197 1,073 4,303 Cash settled stock units 245 244 (439 ) Share-based compensation $ 1,649 $ 1,687 $ 4,178 During each of the years ended December 31, 2017 and 2016 , the Company capitalized $0.1 million of compensation cost related to cash settled restricted stock units to oil and gas properties. No such amounts were capitalized during the year ended December 31, 2015. During the years ended December 31, 2017 , 2016 and 2015 , the Company recorded income tax benefits of approximately $0.3 million , $0.5 million and $1.5 million , respectively, related to share-based compensation expense recognized during those periods. As a result of the Company’s net operating loss position, no excess tax benefits have been recognized for any periods presented. Share-Based compensation settled in shares At December 31, 2017 , the Company had $3.9 million of unrecognized compensation cost related to unvested restricted stock and stock options. This amount will be recognized as compensation expense over a weighted average period of approximately three years . Stock Options Stock options may be granted to employees and consultants and generally vest ratably over a three -year period. Stock options may also be granted to directors and generally vest one year or less from the date of grant to align with their term on the board. Stock options must be exercised within 10 years of the grant date. The exercise price of each option may not be less than the fair market value of a share of common stock on the date of grant. Upon a change in control of the Company, all outstanding options become immediately exercisable. The Company computes the fair value of its stock options using the Black-Scholes option-pricing model assuming an expected term based on historical activity and expected volatility computed using historical stock price fluctuations on a weekly basis for a period of time equal to the expected term of the option. Periodically, the Company adjusts compensation expense based on the difference between actual and estimated forfeitures. There were no stock options granted in 2015 . The following table outlines the assumptions used in computing the fair value of stock options granted during 2017 and 2016 : Years Ended December 31, 2017 2016 Dividend yield —% —% Expected volatility 80.44% 62.0%-79.99% Risk-free rate 1.925% 1.255%-2.09% Expected term 6 years 6 years Stock options granted 219,130 1,168,754 Wgtd. avg. grant date fair value per share $1.28 $1.96 Fair value of grants $280,000 $2,293,000 The following table details stock option activity during the year ended December 31, 2017 : Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Remaining Life Aggregate Intrinsic Value (000’s) Outstanding at beginning of year 1,412,940 $ 7.13 Granted 219,130 1.85 Expired/cancelled/forfeited (23,424 ) 21.49 Exercised — Outstanding at end of year 1,608,646 6.20 8.08 $ 9 Options exercisable at end of year 705,594 $ 10.34 7.00 $ — Options expected to vest 1,563,493 6.29 8.06 $ 8 The total fair value of stock options that vested during the years ended December 31, 2017 , 2016 and 2015 was $1.6 million , $0.4 million and $0.8 million , respectively. The intrinsic value of stock options exercised was immaterial for all periods presented. The following table summarizes information regarding stock options outstanding at December 31, 2017 : Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg. Exercise Outstanding Remaining Exercise Exercisable Exercise Price 12/31/2017 Contractual Life Price 12/31/2017 Price $0.00-$2.49 285,503 9.48 $1.97 22,150 $2.37 $2.50-$3.49 878,833 8.74 $3.17 362,973 $3.17 $3.50-$4.99 206,769 8.38 $4.26 82,930 $4.23 $15.00-$30.32 237,541 3.71 $24.18 237,541 $24.18 1,608,646 705,594 $10.34 Restricted Stock The Company computes the fair value of its service based restricted stock using the closing price of the Company’s stock at the date of grant. Restricted stock granted to employees generally vests ratably over a three -year period. Restricted stock granted to directors vests one year or less from the date of grant to align with their term on the board. Upon a change in control of the Company, all outstanding shares of restricted stock will become immediately vested. The following table details restricted stock activity during the year ended December 31, 2017 : Number of Shares Wgtd. Avg. Fair Value per Share Outstanding at beginning of year 78,557 $16.57 Granted 487,502 $1.87 Lapse of restrictions (78,557 ) $16.57 Outstanding at December 31, 2017 487,502 $1.87 The weighted average grant date fair value of restricted stock granted during the years ended December 31, 2017 and 2015 was $1.87 and $5.08 , respectively, per share. No restricted stock was granted in 2016. The total fair value of restricted stock that vested during the years ended December 31, 2017 , 2016 and 2015 was $1.3 million , $2.4 million and $4.7 million , respectively. Share-Based compensation settled in cash Restricted Stock Units The Company may grant restricted stock units ("RSUs") to employees that vest ratably over a three -year period. Cash payment will be made to employees on each vesting date based upon the Company's closing stock price on that date. Upon change in control of the Company, all of the RSUs will immediately vest. The Company computes the fair value of the RSUs using the closing price of the Company's stock at the end of each period and records a liability based on the percentage of requisite service rendered at the reporting date. During 2017 and 2016 , the Company paid $0.1 million and $0.3 million , respectively, to settle 31,703 and 111,461 RSUs, respectively, that vested during the period. Market Based Restricted Stock Units The Company granted 60,767 market based restricted stock units ("MRSUs") to executive officers during November 2014. The executive officers can earn between 0 - 200% of the MRSUs granted based on the Company's performance versus a defined peer group. The 2014 MRSUs vest in one-third increments on each of the first, second and third annual anniversaries starting January 1, 2016. Upon change in control of the Company, all of the MRSUs will immediately vest. The number of MRSUs that ultimately vest is based on the Company's total shareholder return in the last 20 days of the fiscal year in relation to the last 20 days of the previous fiscal year in comparison to a group of 12 selected peer stocks of similar sized companies which operate within the same sector. The performance period ended on December 31, 2015 and executive officers earned 50% of the MRSUs. The MRSUs are cash settled on each vesting date based on the number of MRSUs that vest multiplied by the Company's closing stock price. In November 2017, the Company granted an additional 270,269 MRSUs. The performance period is scheduled to end on December 31, 2018 for these grants. The Company estimates the fair value of the outstanding MRSUs using a Monte Carlo valuation model and records a liability based on the percentage of requisite service rendered at the reporting date. The Monte Carlo valuation model considers such inputs as the stock prices of the Company and its peer group, a risk-free interest rate, and an estimated volatility for the Company and its peer group. As of December 31, 2017 and December 31, 2016 , the Company had a liability for RSUs and MRSUs outstanding in the amount of $0.3 million and $0.1 million , respectively, based upon the closing stock price at December 31, 2017 and December 31, 2016 . The following table details MRSU and RSU activity during the year ended December 31, 2017 : MRSU RSU Total Outstanding at beginning of year 14,929 31,979 46,908 Granted 270,269 889,587 1,159,856 Expired/Cancelled/Forfeited — (276 ) (276 ) Vested/Paid (7,465 ) (31,703 ) (39,168 ) Outstanding at December 31, 2017 277,733 889,587 1,167,320

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Asset Retirement Obligation The Company accounts for asset retirement obligations in accordance with ASC Topic 410-20, which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred. Asset retirement obligations associated with long-lived assets included within the scope of ASC Topic 410-20 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed. The following table summarizes the changes to the Company’s asset retirement obligation (in thousands): Year Ended December 31, 2017 2016 Asset retirement obligation, beginning of period $ 36,610 $ 42,556 Liabilities incurred 574 — Liabilities settled (3,364 ) (3,296 ) Accretion expense 2,252 2,515 Revisions in estimated cash flows (4,514 ) (1,746 ) Divestiture of oil and gas properties (248 ) (3,419 ) Asset retirement obligation, end of period 31,310 36,610 Less: current portion of asset retirement obligation (687 ) (4,160 ) Long-term asset retirement obligation $ 30,623 $ 32,450 Divestitures of oil and gas properties during 2016 included $3.3 million as a result of the sale of our remaining Oklahoma assets. The liabilities incurred, revisions in estimated cash flows and divestitures represent non-cash investing activities for purposes of the statement of cash flows. In January 2018, the Company completed the sale of the Sold Assets, which resulted in a reduction of $28.4 million to our discounted asset retirement obligation subsequent to December 31, 2017 .

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the statement of operations as derivative income (expense). At December 31, 2017 and 2016 , all of the Company's outstanding derivative instruments were designated as cash flow hedges. Oil and gas sales include additions related to the settlement of gas hedges of $1.5 million , $1.8 million and $15.9 million , for the years ended December 31, 2017 , 2016 and 2015 , respectively. There were no settlements of Ngl or oil hedges for the years ended December 31, 2017 and 2016 . Oil and gas sales include $0.5 million and $0.6 million related to settlements of Ngl and oil hedges, respectively, for the year ended December 31, 2015 . As of December 31, 2017 , the Company had entered into the following gas and oil hedge contracts: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: January 2018 - March 2018 Swap 35,000 Mmbtu $3.24 Crude Oil: January 2018 - December 2018 Swap 250 Bbl $55.00 At December 31, 2017 , the Company had recognized a net asset of approximately $0.4 million related to the estimated fair value of these derivative contracts. Based on estimated future commodity prices as of December 31, 2017 , the Company would realize a $0.3 million gain , net of taxes, during the next 12 months. This gain is expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts. Derivatives designated as hedging instruments: The following tables reflect the fair value of the Company’s effective cash flow hedges in the consolidated financial statements (in thousands): Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2017 and December 31, 2016 : Commodity Derivatives Period Balance Sheet Fair Value December 31, 2017 Derivative asset $ 1,174 December 31, 2017 Derivative liability $ (731 ) December 31, 2016 Derivative liability $ (3,947 ) December 31, 2016 Other long-term liabilities $ (803 ) Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2017 , 2016 and 2015 : Instrument Amount of Gain (Loss) Location of Amount of Gain Reclassified into Commodity Derivatives at December 31, 2017 $ 6,654 Oil and gas sales $ 1,461 Commodity Derivatives at December 31, 2016 $ (4,447 ) Oil and gas sales $ 1,811 Commodity Derivatives at December 31, 2015 $ 9,991 Oil and gas sales $ 17,114

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC Topic 820 defines fair value as the price 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 and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels: • Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority; • Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability; • Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority. The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company's derivative instruments at December 31, 2017 and 2016 were in the form of swaps based on NYMEX pricing for oil and natural gas. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy. The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis as of December 31, 2017 and December 31, 2016 (in thousands): Fair Value Measurements Using Instrument Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives: At December 31, 2017 $ — $ 443 $ — At December 31, 2016 $ — $ (4,750 ) $ — The fair value of the Company's cash and cash equivalents approximated book value at December 31, 2017 and 2016 . The fair value of the Multidraw Term Loan Agreement approximated face value as of December 31, 2017 and 2016 . The fair value of the Company's 2017 Notes, 2021 Notes and 2021 PIK Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input. The following table summarizes the fair value of the 2017 Notes, 2021 Notes and 2021 PIK Notes as of December 31, 2017 and 2016 , respectively (in thousands). Fair Value at 12/31/17 Face Value at 12/31/17 Carrying value at 12/31/17 Fair Value at 12/31/16 Face Value at 12/31/16 Carrying value at 12/31/16 2017 Notes $ — $ — $ — $ 21,970 $ 22,650 $ 22,568 2021 Notes 7,306 9,427 9,821 12,192 14,177 15,228 2021 PIK Notes 198,717 263,202 271,577 177,732 243,468 248,600 $ 206,023 $ 272,629 $ 281,398 $ 211,894 $ 280,295 $ 286,396

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017. On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively, the "2017 Notes"). On February 17, 2016, the Company closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, the Company (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of its new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 1.1 million shares of common stock. Following the completion of the February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes. On September 27, 2016 , the Company closed private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes and 2021 Notes. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then outstanding aggregate principal amount of 2021 Notes, the Company issued (i) $243.5 million in aggregate principal amount of its new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of common stock. The Company also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016 . Following the consummation of the September Exchange, there were $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes. On March 31, 2017, the Company redeemed its remaining outstanding 2017 Notes at a redemption price of $22.8 million . The redemption was funded by cash on hand and amounts borrowed under the Multidraw Term Loan Agreement described below. On December 28, 2017, the Company issued 2.2 million shares of common stock to extinguish approximately $4.8 million of outstanding principal amount of 2021 Notes. The 2021 PIK Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year, starting on February 15, 2017. The Company was permitted, at its option, for one or more of the first three interest payment dates of the 2021 PIK Notes, to instead pay interest at (i) the annual rate of 1% in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. The Company exercised this PIK option in connection with the interest payments due on February 15, 2017, August 15, 2017 and February 15, 2018. As of December 31, 2017 , the Company was in compliance with all of the covenants under the 2021 PIK Notes. The 2021 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year. As of December 31, 2017 , the Company was in compliance with all of the covenants under the 2021 Notes. The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to ASC Topic 470-60 "Troubled Debt Restructurings by Debtors." The Company determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million is reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall is being amortized under the effective interest method over the term of the 2021 PIK Notes. At December 31, 2017 , $0.5 million of the excess remained as part of the carrying value of the 2021 PIK Notes and the Company recognized $0.1 million of amortization expense as a increase to interest expense during the year ended December 31, 2017 . The Company previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange is now reflected as part of the carrying value of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes is being amortized under the effective interest method over the term of the 2021 Notes. At December 31, 2017 , $0.6 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $0.6 million of amortization expense as a reduction to interest expense during the year ended December 31, 2017 . The issuance of the 2021 Notes, 2021 PIK Notes and shares of common stock, as wells as the exchange of the 2017 Notes and 2021 Notes in the February Exchange and September Exchange, represent non-cash financing activities for purposes of the statement of cash flows. The indentures governing the 2021 PIK Notes and the 2021 Notes contain affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the 2021 PIK Notes and the 2021 Notes to incur indebtedness; purchase or redeem stock; make certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The 2021 PIK Notes and the 2021 Notes are fully and unconditionally guaranteed on a senior basis, jointly and severally, by certain wholly-owned subsidiaries of the Company. The 2021 PIK Notes and the 2021 Notes are secured equally and ratably by second-priority liens on substantially all of the Company's and the subsidiary guarantors' oil and gas properties and substantially all of their other assets to the extent such properties and assets secure the Multidraw Term Loan Agreement (as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security interest in those properties and assets that secure the 2021 PIK Notes and the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Multidraw Term Loan Agreement and certain other permitted indebtedness. Consequently, the 2021 PIK Notes and the 2021 Notes and the guarantees will be effectively subordinated to the Multidraw Term Loan Agreement and such other indebtedness to the extent of the value of such assets. On October 17, 2016 , the Company entered into the Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the credit agreement with JPMorgan Chase Bank, N.A. The Multidraw Term Loan Agreement provides a multi-advance term loan facility, with borrowing availability for three years, in a principal amount of up to $50.0 million . The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. The Term Loans mature on October 17, 2020 . As of December 31, 2017 , the Company has $30.0 million of borrowings outstanding under the Term Loans. The Company’s obligations under the Multidraw Term Loan Agreement and the Term Loans are secured by a first priority lien on substantially all of the assets of the Company and certain of its subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the oil and gas properties of the Company and its subsidiaries, a pledge of the equity interests of PetroQuest Energy, L.L.C. (the "Borrower") and certain of the Company’s other subsidiaries, and corporate guarantees of the Company and certain of the Company’s other subsidiaries of the indebtedness of the Borrower. Term Loans under the Multidraw Term Loan Agreement bear interest at the rate of 10% per annum. The Company and its subsidiaries are subject to a restrictive financial covenant under the Multidraw Term Loan Agreement, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of the Company’s and its subsidiaries’ oil and gas properties, before any state, federal, foreign or other income taxes, attributable to proved developed reserves, using three-year strip prices in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the outstanding Term Loans and the then outstanding commitments to provide Term Loans, that shall not be less than 2.0 to 1.0 as measured on the last day of each calendar quarter (the "Coverage Ratio"). Sales of the Company’s and its subsidiaries’ oil and gas properties outside the ordinary course of business are limited under the terms of the Multidraw Term Loan Agreement. In addition, the Multidraw Term Loan Agreement prohibits the Company from declaring and paying dividends on its Series B Preferred Stock. The Multidraw Term Loan Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. As of December 31, 2017 , no default or event of default existed under the Multidraw Term Loan Agreement and the Company was in compliance with all covenants contained in the Multidraw Term Loan Agreement, including the Coverage Ratio. The 2017 Notes are reflected net of $0.1 million of related unamortized financing costs at December 31, 2016. The 2021 Notes are reflected net of $0.2 million and $0.1 million of related unamortized financing costs as of December 31, 2017 and 2016 , respectively, and the Term Loans are reflected net of $2.0 million and $2.8 million of related unamortized financing costs as of December 31, 2017 and 2016 , respectively. The following table reconciles the face value of the 2017 Notes, 2021 Notes, 2021 PIK Notes and Term Loans to the carrying value included in the consolidated balance sheet as of December 31, 2017 and 2016 (in thousands): December 31, 2017 December 31, 2016 2017 Notes 2021 Notes 2021 PIK Notes Term Loans 2017 Notes 2021 Notes 2021 PIK Notes Term Loans Face Value $ — $ 9,427 $ 263,202 $ 30,000 $ 22,650 $ 14,177 $ 243,468 $ 10,000 Unamortized Deferred Financing Costs — (212 ) — (2,037 ) (82 ) (108 ) — (2,751 ) Excess (shortfall) Carrying Value — 606 (508 ) — — 1,159 (590 ) — Accrued PIK Interest — — 8,883 — — — 5,722 — Carrying Value $ — $ 9,821 $ 271,577 $ 27,963 $ 22,568 $ 15,228 $ 248,600 $ 7,249

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Two of the Company’s senior officers, Charles T. Goodson and Stephen H. Green, or their affiliates, are working interest owners and overriding royalty interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest owners, they are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, they are entitled to receive their proportionate share of revenues in the normal course of business. During 2017 , in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to (received from) Messrs. Goodson and Green, or their affiliates, in the amounts of $(107,000) and $41,000 , respectively. During 2016 , in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to (received from) Messrs. Goodson and Green, or their affiliates, in the amounts of $(15,000) and $25,000 , respectively. During 2015 , in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to (received from) Messrs. Goodson and Green, or their affiliates, in the amounts of $(45,000) and $30,000 , respectively. With respect to Mr. Goodson, gross revenues attributable to interests, properties or participation rights held by him prior to joining the Company as an officer and director on September 1, 1998 represent all of the gross revenue received by him during these periods. In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests. At December 31, 2017 , the Company’s joint interest billing receivable included approximately $89,000 from the related parties discussed above or their affiliates, attributable to their share of costs. This represents 1% of the Company’s total joint interest billing receivable at December 31, 2017 . In December 2017, the Company sold certain saltwater disposal assets in East Texas to a third party purchaser. In connection with the sale, the Company also entered into a volumetric commitment to deliver saltwater volumes to the purchaser of the saltwater disposal assets over a six year period. One of the minority owners of the purchaser is the son of Dr. Charles Mitchell, II, a member of our board of directors. The transactions were approved by the Audit Committee.

Ceiling Test Write-down

Ceiling Test Write-down	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Ceiling Test Write-down	Ceiling Test Write-down The Company uses the full cost method to account for its oil and gas properties. Accordingly, the costs to acquire, explore for and develop oil and gas properties are capitalized. Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from estimated proved oil and gas reserves, including the effects of cash flow hedges in place, discounted at 10% , plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to ceiling test write-down of oil and gas properties in the quarter in which the excess occurs. In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and market differentials. At December 31, 2016 and 2015 , the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $2.51 and $2.42 , respectively, per Mcf of natural gas, $40.85 and $50.29 , respectively, per barrel of oil and $1.82 and $2.21 , respectively, per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of approximately $40.3 million and $266.6 million , respectively, during the years ended December 31, 2016 and 2015 . The Company’s cash flow hedges in place decreased these ceiling test write-downs by approximately $8 million and $1.1 million for the years ended December 31, 2016 and 2015 , respectively. The Company did not recognize a ceiling test write-down during the year ended December 31, 2017 .

Other Comprehensive Income (Los

Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Other Comprehensive Income (Loss)	Other Comprehensive Income (Loss) The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2015 (in thousands): Gains and Losses on Cash Flow Hedges Balance as of December 31, 2014 $5,420 Other comprehensive income before reclassifications: Change in fair value of derivatives 9,991 Income tax effect (3,716 ) Net of tax 6,275 Amounts reclassified from accumulated other comprehensive income: Oil and gas sales (17,114 ) Income tax effect 6,366 Net of tax (10,748 ) Net other comprehensive loss (4,473 ) Balance as of December 31, 2015 $947 The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2016 (in thousands): Gains and Losses on Cash Flow Hedges Change in Valuation Allowance Total Balance as of December 31, 2015 $ 947 $ — $ 947 Other comprehensive income before reclassifications: Change in fair value of derivatives (4,447 ) — (4,447 ) Income tax effect 1,654 (1,654 ) — Net of tax (2,793 ) (1,654 ) (4,447 ) Amounts reclassified from accumulated other comprehensive income: Oil and gas sales (1,811 ) — (1,811 ) Income tax effect 674 (113 ) 561 Net of tax (1,137 ) (113 ) (1,250 ) Net other comprehensive loss (3,930 ) (1,767 ) (5,697 ) Balance as of December 31, 2016 $ (2,983 ) $ (1,767 ) $ (4,750 ) The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2017 (in thousands): Gains and Losses on Cash Flow Hedges Change in Valuation Allowance Total Balance as of December 31, 2016 $ (2,983 ) $ (1,767 ) $ (4,750 ) Other comprehensive income before reclassifications: Change in fair value of derivatives 6,654 — 6,654 Income tax effect (2,475 ) 1,767 (708 ) Net of tax 4,179 1,767 5,946 Amounts reclassified from accumulated other comprehensive income: Oil and gas sales (1,461 ) — (1,461 ) Income tax effect 543 — 543 Net of tax (918 ) — (918 ) Net other comprehensive loss 3,261 1,767 5,028 Balance as of December 31, 2017 $ 278 $ — $ 278

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company typically provides for income taxes at the statutory federal income tax rate adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of ceiling test write-downs, the Company has incurred a three -year cumulative loss. Because of the impact the cumulative loss had on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities. The Company had a valuation allowance of $115.9 million as of December 31, 2017 and $177.4 million as of December 31, 2016 . The Tax Cuts and Jobs Act (the “Act”) was enacted on December 22, 2017. The Act, among other things, reduces the U.S. federal corporate tax rate from 35% to 21% , eliminates the corporate alternative minimum tax and changes how existing alternative minimum tax credits are realized, creates a new limitation on deductible interest expense and changes the rules related to uses and limitations of net operating loss carryforwards generated in tax years beginning after December 31, 2017. As of December 31, 2017 , the Company has not completed its accounting for the tax effects of enactment of the Act. However, the Company has made a reasonable estimate of the effects on its existing deferred tax balances and recognized a provisional amount of $64.9 million to remeasure deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21% . This amount is included as a component of income tax expense (benefit) from continuing operations and is fully offset by the related adjustment to the Company’s valuation allowance. The Company is still analyzing certain aspects of the Act and refining its calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. As a result of the adoption of ASU 2016-09, the Company recognized an additional deferred tax asset of $4.7 million related to net operating loss carryforwards for excess tax benefits on share-based compensation that did not meet the criteria for recognition under previous guidance. This additional deferred tax asset was fully offset by the related adjustment to the Company's valuation allowance. The cumulative effect adjustment to record the previously unrecognized excess tax benefits and the related adjustment to the valuation allowance, were recorded in retained earnings on the date of adoption. An analysis of the Company’s deferred tax assets and liabilities follows (amounts in thousands): December 31, 2017 2016 Net operating loss carryforwards $ 78,541 $ 92,072 Percentage depletion carryforward 5,701 9,372 Alternative minimum tax credits — 784 Contributions carryforward and other 192 282 Temporary differences: Oil and gas properties 8,279 27,992 Asset retirement obligation 7,602 13,620 Derivatives (107 ) 1,767 Share-based compensation 1,269 1,870 Original issue discount on debt exchanges 14,429 29,646 Valuation allowance (115,906 ) (177,405 ) Deferred tax asset (liability) $ — $ — At December 31, 2017 , the Company had approximately $332.1 million of federal net operating loss carryforwards. If not utilized, approximately $6.9 million of such carryforwards would expire in 2025 and the remainder would expire by the year 2037 . The Company also had approximately $139.4 million of Louisiana state net operating loss carryforwards as of December 31, 2017 . If not utilized, approximately $3.2 million of such carryforwards would expire during 2018 and the remainder would expire by the year 2036 . The Company has available for tax reporting purposes $26.9 million in statutory depletion deductions that may be carried forward indefinitely. Income tax expense (benefit) for each of the years ended December 31, 2017 , 2016 and 2015 was different than the amount computed using the federal statutory rate (35%) for the following reasons (amounts in thousands): For the Year Ended December 31, 2017 2016 2015 Amount computed using the statutory rate $ (2,655 ) $ (31,623 ) $ (102,257 ) Increase (reduction) in taxes resulting from: Impact of rate change on deferred tax 64,915 — — State & local taxes (368 ) (2,000 ) (6,477 ) Percentage depletion carryforward (66 ) (163 ) (404 ) Non-deductible stock option expense (1) 305 77 90 Share-based compensation (2) 64 707 1,317 Other (21 ) 1,415 113 Change in valuation allowance (63,123 ) 32,130 110,244 Income tax expense (benefit) $ (949 ) $ 543 $ 2,626 (1) Relates to compensation expense related to Incentive Stock Options. (2) Relates to the write-off of deferred tax assets associated with share-based compensation that will not be deductible for tax purposes.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The Company is involved in litigation relating to claims arising out of its operations in the normal course of business, including worker's compensation claims, tort claims and contractual disputes. Some of the existing known claims against us are covered by insurance subject to the limits of such policies and the payment of deductible amounts by us. Although we cannot predict the outcome of these proceedings with certainty, management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on the Company's business or financial position. Lease Commitments The Company has operating leases for office space and equipment, which expire on various dates through 2023. Future minimum lease commitments as of December 31, 2017 under these operating leases are as follows (in thousands): 2018 $ 1,278 2019 1,242 2020 1,175 2021 447 2022 433 Thereafter 392 $ 4,967 Total rent expense under operating leases was approximately $1.5 million , $1.5 million and $1.7 million in 2017 , 2016 and 2015 , respectively.

Supplementary Information on Oi

Supplementary Information on Oil and Gas Operations—Unaudited	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplementary Information of Oil and Gas Operations—Unaudited	Supplementary Information on Oil and Gas Operations—Unaudited The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are located onshore and offshore in the continental United States: Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities ( amounts in thousands ) For the Year-Ended December 31, 2017 2016 2015 Acquisition costs: Proved $ 1,330 $ 3,346 $ 2,287 Unproved (1) 12,762 2,197 2,550 Divestiture of proved leasehold (4,795 ) (7,000 ) — Exploration costs: Proved 9,466 715 29,322 Unproved (287 ) 603 7,677 Development costs 32,622 1,522 9,888 Capitalized general and administrative and interest costs 8,269 7,558 12,881 Total costs incurred $ 59,367 $ 8,941 $ 64,605 For the Year-Ended December 31, 2017 2016 2015 Accumulated depreciation, depletion and amortization (DD&A) Balance, beginning of year $ (1,243,286 ) $ (1,157,455 ) $ (1,648,060 ) Provision for DD&A (31,667 ) (27,962 ) (62,138 ) Ceiling test writedown — (40,304 ) (266,562 ) Sale of proved properties and other (2) (3) (10,707 ) (17,565 ) 819,305 Balance, end of year $ (1,285,660 ) $ (1,243,286 ) $ (1,157,455 ) DD&A per Mcfe $ 1.15 $ 1.19 $ 1.82 (1) During 2017 , the Company acquired approximately 24,600 gross acres for approximately $9.3 million of cash and 2.0 million shares of common stock. (2) During 2015 , the Company sold its Woodford Shale and Mississippian Lime assets for an aggregate cash purchase price of $274.1 million (see Note 2). (3) During 2017 , the Company sold its East Lake Verret assets for net proceeds of approximately $2.2 million and its East Texas saltwater disposal assets for net proceeds of $8.5 million . During 2016 , the Company sold its remaining Oklahoma producing assets for an aggregate purchase price of $17.6 million . During 2015 , the Company sold its Fort Trinidad assets for net proceeds of approximately $0.5 million and its East Haynesville assets for net proceeds of approximately $0.1 million . At December 31, 2017 and 2016 , unevaluated oil and gas properties totaled $21.9 million and $9.0 million , respectively, and were not subject to depletion. Unevaluated costs at December 31, 2017 included $0.7 million related to two facilities in progress at year-end. At December 31, 2016 , unevaluated costs included $0.4 million related to one development well in progress at year-end, which were transferred to evaluated oil and gas properties during 2017 . The Company capitalized $1.6 million , $0.9 million and $4.7 million of interest during 2017 , 2016 and 2015 , respectively. Of the total unevaluated oil and gas property costs of $21.9 million at December 31, 2017 , $14.6 million , or 67% , was incurred in 2017 , $2.0 million , or 9% , was incurred in 2016 and $5.2 million , or 24% , was incurred in prior years. In connection with the sale of the Company's Gulf of Mexico assets, approximately $5.5 million , or 25% of the total unevaluated balance at December 31, 2017 , was transferred to evaluated oil and gas properties in 2018. Of the remaining unevaluated balance at December 31, 2017 , the Company expects the majority of the costs will be evaluated within the next three years, including $4.1 million expected to be evaluated during 2018 . Oil and Gas Reserve Information The Company’s net proved oil and gas reserves at December 31, 2017 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-month, first of month, average pricing assumption. The estimates of proved oil and gas reserves constitute those quantities of oil, gas,and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties or the cost that would be incurred to obtain equivalent reserves. The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil (including condensate), gas and natural gas liquid reserves, all located onshore and offshore in the continental United States: Oil NGL Natural Gas Total Proved reserves as of December 31, 2014 2,437 73,498 309,025 397,148 Revisions of previous estimates (211 ) (3,571 ) (9,852 ) (14,698 ) Extensions, discoveries and other additions 163 16,078 45,645 62,702 Sale of reserves in place (54 ) (45,692 ) (186,972 ) (232,988 ) Production (529 ) (5,487 ) (25,502 ) (34,160 ) Proved reserves as of December 31, 2015 1,806 34,826 132,344 178,004 Revisions of previous estimates 247 (4,380 ) (11,854 ) (14,748 ) Extensions, discoveries and other additions — — 1,485 1,485 Sale of reserves in place (154 ) — (24,834 ) (25,759 ) Production (502 ) (3,871 ) (16,617 ) (23,501 ) Proved reserves as of December 31, 2016 1,397 26,575 80,524 115,481 Revisions of previous estimates 308 (7,269 ) 381 (5,040 ) Extensions, discoveries and other additions 777 4,565 64,704 73,931 Purchase of producing properties 48 — 473 761 Sale of reserves in place (90 ) — (1,033 ) (1,573 ) Production (592 ) (4,450 ) (19,611 ) (27,613 ) Proved reserves as of December 31, 2017 1,848 19,421 125,438 155,947 Proved developed reserves As of December 31, 2015 1,549 15,792 78,533 103,615 As of December 31, 2016 1,212 13,073 47,349 67,694 As of December 31, 2017 1,078 12,564 57,409 76,441 Proved undeveloped reserves As of December 31, 2015 257 19,034 53,811 74,389 As of December 31, 2016 185 13,502 33,175 47,787 As of December 31, 2017 770 6,857 68,029 79,506 Year Ended December 31, 2017 During 2017 , the Company’s estimated proved reserves increase d by 35% . The increase in reserves was the result of 73.9 Bcfe added due to the Company's drilling program in East Texas where it drilled eight gross wells during 2017 . In response to low ethane prices, during 2017 the Company elected to bypass ethane processing on a portion of its East Texas production. As a result, the Company reduced its estimated proved ngl reserves to reflect the assumption that ethane would continue to not be recovered as natural gas liquids. Overall, the Company had a 100% drilling success rate during 2017 . Year Ended December 31, 2016 During 2016 , the Company’s estimated proved reserves decrease d by 35% primarily due to the divestiture of the Company's remaining Oklahoma assets and significant reductions in capital spending during 2016 . Extensions, discoveries and other additions of 1.5 Bcfe were primarily due to the successful completion of the Company's final Oklahoma wells. Revisions of previous estimates included the reclassification of certain PUD reserves to probable reserves as a result of the Company's assessment of the timing of development. Overall, the Company had a 100% drilling success rate during 2016 on 5 gross wells drilled. Year Ended December 31, 2015 During 2015 , the Company's estimated proved reserves decrease d by 55% primarily due to the divestiture of the majority of the Company's Woodford Shale and Mississippian Lime assets. Extensions, discoveries and other additions of 63 Bcfe were primarily due to successful drilling programs in the Company's Oklahoma and East Texas fields. The Company added approximately 17 Bcfe of proved reserves in Oklahoma and 44 Bcfe in Texas. Overall, the Company had a 95% drilling success rate during 2015 on 56 gross wells drilled. The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by ASC Topic 932. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate. Standardized Measure December 31, 2017 2016 2015 Future cash flows $ 539,244 $ 299,035 $ 487,834 Future production costs (184,171 ) (117,283 ) (171,678 ) Future development costs (128,447 ) (83,720 ) (116,591 ) Future income taxes — — — Future net cash flows 226,626 98,032 199,565 10% annual discount (99,329 ) (30,763 ) (71,880 ) Standardized measure of discounted future net cash flows $ 127,297 $ 67,269 $ 127,685 Changes in Standardized Measure Year Ended December 31, 2017 2016 2015 Standardized measure at beginning of year $ 67,269 $ 127,685 $ 548,562 Sales and transfers of oil and gas produced, net of production costs (70,362 ) (35,993 ) (55,849 ) Changes in price, net of future production costs 53,516 (30,427 ) (267,710 ) Extensions and discoveries, net of future production and development costs 50,977 864 70,928 Changes in estimated future development costs, net of development costs incurred during this period 17,144 26,356 31,007 Revisions of quantity estimates (7,482 ) (14,889 ) (14,427 ) Accretion of discount 6,727 12,769 60,071 Net change in income taxes — — 52,149 Purchase of reserves in place 549 — — Sale of reserves in place (1,305 ) (16,701 ) (194,454 ) Changes in production rates (timing) and other 10,264 (2,395 ) (102,592 ) Net increase (decrease) in standardized measure 60,028 (60,416 ) (420,877 ) Standardized measure at end of year $ 127,297 $ 67,269 $ 127,685 The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were: 2017 2016 2015 Oil, $/Bbl $52.49 $40.85 $50.29 Ngls, $/Mcfe 3.23 2.40 2.24 Natural Gas, $/Mcf 3.03 1.82 2.41

Summarized Quarterly Financial

Summarized Quarterly Financial Information - Unaudited	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Information - Unaudited	Summarized Quarterly Financial Information - Unaudited Summarized quarterly financial information is as follows (amounts in thousands except per share data): Quarter Ended March 31 June 30 September 30 December 31 2017 Revenues $ 20,772 $ 24,251 $ 28,184 $ 35,080 Income (loss) from operations (3,633 ) (2,289 ) (1,885 ) 221 Loss available to common stockholders (4,918 ) (3,385 ) (3,085 ) $ (389 ) Loss per share: Basic $ (0.23 ) $ (0.16 ) $ (0.15 ) $ (0.02 ) Diluted $ (0.23 ) $ (0.16 ) $ (0.15 ) $ (0.02 ) 2016: Revenues $ 17,320 $ 15,824 $ 17,094 $ 16,429 Loss from operations (1) (37,557 ) (22,383 ) (22,039 ) (8,374 ) Loss available to common stockholders (1) (39,137 ) (24,143 ) (23,306 ) (9,659 ) Loss per share: Basic $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) Diluted $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) 2016 included pretax ceiling test write-downs of $18.9 million , $12.8 million and $8.7 million , respectively.

Organization and Summary of S25

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of PetroQuest and its subsidiaries, PetroQuest Energy, L.L.C., PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC (collectively, the "Company"). All intercompany accounts and transactions have been eliminated.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserves and future net cash flows from estimated proved reserves are based on geological and engineering data and depend upon a number of variable factors and assumptions. Changes in estimated proved oil and gas reserves used in the calculation of depreciation, depletion and amortization of oil and gas properties or the present value of the estimated future net cash flows from estimated proved reserves used in the ceiling test could have a material impact on future results of operations.
Oil and Gas Properties	Oil and Gas Properties The Company utilizes the full cost method of accounting, which involves capitalizing all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves including the costs of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes the portion of general and administrative costs that can be directly identified with acquisition, exploration or development of oil and gas properties. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold, or management determines these costs to have been impaired. Interest is capitalized on unevaluated property costs. Transactions involving sales of reserves in place are recorded as adjustments to accumulated depreciation, depletion and amortization with no gain or loss recognized, unless such adjustments would cause a significant alteration in the relationship between capitalized costs and proved reserves. Depreciation, depletion and amortization of oil and gas properties is computed using the unit-of-production method based on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development costs associated therewith, are included in the depreciable base. The costs of investments in unevaluated properties are excluded from this calculation until the related properties are evaluated, proved reserves are established or the properties are determined to be impaired. Proved oil and gas reserves are estimated annually by independent petroleum engineers. The capitalized costs of proved oil and gas properties cannot exceed the present value of the estimated net future cash flows from proved reserves based on historical twelve-month, first day of the month, average oil, gas and natural gas liquid prices, including the effect of hedges in place (the full cost ceiling). If the capitalized costs of proved oil and gas properties exceed the full cost ceiling, the Company is required to write-down the value of its oil and gas properties to the full cost ceiling amount. The Company follows the provisions of Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of Accounting Standards Codification ("ASC") Topic 410-20 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with a stated maturity of three months or less to be cash and cash equivalents. The majority of the Company’s cash and cash equivalents are in overnight securities made through its commercial bank accounts, which result in available funds the next business day.
Accounts Receivable	Accounts Receivable In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests.
Other Property and Equipment	Other Property and Equipment The costs related to other furniture and fixtures are depreciated on a straight line basis over estimated useful lives ranging from three to five years.
Deposit For Surety Bonds	Deposit For Surety Bonds The deposit for surety bonds of $8.3 million at December 31, 2017 represents cash collateral paid with respect to the Company's surety bonds which secure its offshore decommissioning obligations.
Income Taxes	Income Taxes The Company accounts for income taxes in accordance with ASC Topic 740. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, the Company may use certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs. Other financial and income tax reporting differences occur primarily as a result of statutory depletion. Deferred tax assets are assessed for realizability and a valuation allowance is established for any portion of the asset for which it is more likely than not will not be realized.
Revenue Recognition	Revenue Recognition The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties.
Concentrations	Concentrations The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary.
Derivatives Instruments	Derivative Instruments Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is effective. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the statement of operations as derivative income (expense). The Company does not offset fair value amounts recognized for derivative instruments. The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2017 , the Company’s derivative instruments were designated as effective cash flow hedges. See Note 7 for further discussion of the Company’s derivative instruments.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods and or services. In August 2015, the FASB issued ASU 2015-14 deferring the effective date of ASU 2014-09 by one year to interim and annual periods beginning on or after December 31, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. The Company adopted the new standard effective January 1, 2018 using the modified retrospective approach. The adoption of the standard did not have a material impact on the Company's consolidated financial statements, but will result in increased disclosures related to revenue recognition policies and disaggregation of revenues. In February 2016, the FASB issued ASU 2016-02, " Leases (Topic 842), " to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. The Company is currently evaluating the effect that this new standard may have on its consolidated financial statements. In March 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation (Topic 718)," to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The Company adopted ASU 2016-09 on January 1, 2017, and the adoption of the standard did not have a material impact on the Company's consolidated financial statements. In August 2017, the FASB issued ASU 2017-12, "Derivative and Hedging," to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its consolidated financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. ASU 2017-12 is effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with earlier application permitted. The Company is currently evaluating the effect that this new standard may have on its consolidated financial statements.

Organization and Summary of S26

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of significant concentration risk	The following table identifies customers from whom the Company derived 10% or more of its oil and gas revenues during the years presented. Based on the availability of other customers, the Company does not believe the loss of any of these customers would have a significant effect on its business or financial condition. Year Ended December 31, 2017 2016 2015 Superior Natural Gas 29% 14% (a) Shell Trading Company 24% 23% 18% Laclede Energy Resources (a) 17% 21% BG Group (a) 10% 10% Unimark, LLC (a) (a) 17% (a) Less than 10 percent

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
A reconciliation between basic and diluted earnings per share computations	A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share amounts) is as follows: For the Year Ended December 31, 2017 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (11,776 ) 21,330 $ (0.55 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (11,776 ) 21,330 $ (0.55 ) For the Year Ended December 31, 2016 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (96,245 ) 18,354 $ (5.24 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (96,245 ) 18,354 $ (5.24 ) For the Year Ended December 31, 2015 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (299,929 ) 16,256 $ (18.45 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (299,929 ) 16,256 $ (18.45 )

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of share-based compensation	A detail of share-based compensation cost for the years ended December 31, 2017 , 2016 and 2015 is as follows (in thousands): Year Ended December 31, 2017 2016 2015 Stock options: Incentive Stock Options (share settled) $ 820 $ 206 $ 243 Non-Qualified Stock Options (share settled) 387 164 71 Restricted stock (share settled) 197 1,073 4,303 Cash settled stock units 245 244 (439 ) Share-based compensation $ 1,649 $ 1,687 $ 4,178
Schedule of stock option valuation assumptions	The following table outlines the assumptions used in computing the fair value of stock options granted during 2017 and 2016 : Years Ended December 31, 2017 2016 Dividend yield —% —% Expected volatility 80.44% 62.0%-79.99% Risk-free rate 1.925% 1.255%-2.09% Expected term 6 years 6 years Stock options granted 219,130 1,168,754 Wgtd. avg. grant date fair value per share $1.28 $1.96 Fair value of grants $280,000 $2,293,000
Schedule of stock options activity	The following table details stock option activity during the year ended December 31, 2017 : Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Remaining Life Aggregate Intrinsic Value (000’s) Outstanding at beginning of year 1,412,940 $ 7.13 Granted 219,130 1.85 Expired/cancelled/forfeited (23,424 ) 21.49 Exercised — Outstanding at end of year 1,608,646 6.20 8.08 $ 9 Options exercisable at end of year 705,594 $ 10.34 7.00 $ — Options expected to vest 1,563,493 6.29 8.06 $ 8
Schedule of stock option plans, by exercise price range	The following table summarizes information regarding stock options outstanding at December 31, 2017 : Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg. Exercise Outstanding Remaining Exercise Exercisable Exercise Price 12/31/2017 Contractual Life Price 12/31/2017 Price $0.00-$2.49 285,503 9.48 $1.97 22,150 $2.37 $2.50-$3.49 878,833 8.74 $3.17 362,973 $3.17 $3.50-$4.99 206,769 8.38 $4.26 82,930 $4.23 $15.00-$30.32 237,541 3.71 $24.18 237,541 $24.18 1,608,646 705,594 $10.34
Schedule of restricted stock units activity	The following table details MRSU and RSU activity during the year ended December 31, 2017 : MRSU RSU Total Outstanding at beginning of year 14,929 31,979 46,908 Granted 270,269 889,587 1,159,856 Expired/Cancelled/Forfeited — (276 ) (276 ) Vested/Paid (7,465 ) (31,703 ) (39,168 ) Outstanding at December 31, 2017 277,733 889,587 1,167,320 The following table details restricted stock activity during the year ended December 31, 2017 : Number of Shares Wgtd. Avg. Fair Value per Share Outstanding at beginning of year 78,557 $16.57 Granted 487,502 $1.87 Lapse of restrictions (78,557 ) $16.57 Outstanding at December 31, 2017 487,502 $1.87

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Changes to the Company's asset retirement obligation liability	The following table summarizes the changes to the Company’s asset retirement obligation (in thousands): Year Ended December 31, 2017 2016 Asset retirement obligation, beginning of period $ 36,610 $ 42,556 Liabilities incurred 574 — Liabilities settled (3,364 ) (3,296 ) Accretion expense 2,252 2,515 Revisions in estimated cash flows (4,514 ) (1,746 ) Divestiture of oil and gas properties (248 ) (3,419 ) Asset retirement obligation, end of period 31,310 36,610 Less: current portion of asset retirement obligation (687 ) (4,160 ) Long-term asset retirement obligation $ 30,623 $ 32,450

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Oil and gas contracts	As of December 31, 2017 , the Company had entered into the following gas and oil hedge contracts: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: January 2018 - March 2018 Swap 35,000 Mmbtu $3.24 Crude Oil: January 2018 - December 2018 Swap 250 Bbl $55.00 At December 31, 2017 , the Company had recognized a net asset of approximately $0.4 million related to the estimated fair value of these derivative contracts. Based on estimated future commodity prices as of December 31, 2017 , the Company would realize a $0.3 million gain , net of taxes, during the next 12 months. This gain is expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts.
Effect of cash flow hedges on the consolidated balance sheet	Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2017 and December 31, 2016 : Commodity Derivatives Period Balance Sheet Fair Value December 31, 2017 Derivative asset $ 1,174 December 31, 2017 Derivative liability $ (731 ) December 31, 2016 Derivative liability $ (3,947 ) December 31, 2016 Other long-term liabilities $ (803 )
Effect of cash flow hedges on the consolidated statement of operations	Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2017 , 2016 and 2015 : Instrument Amount of Gain (Loss) Location of Amount of Gain Reclassified into Commodity Derivatives at December 31, 2017 $ 6,654 Oil and gas sales $ 1,461 Commodity Derivatives at December 31, 2016 $ (4,447 ) Oil and gas sales $ 1,811 Commodity Derivatives at December 31, 2015 $ 9,991 Oil and gas sales $ 17,114

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Net Valuation of Derivatives	The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis as of December 31, 2017 and December 31, 2016 (in thousands): Fair Value Measurements Using Instrument Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives: At December 31, 2017 $ — $ 443 $ — At December 31, 2016 $ — $ (4,750 ) $ —
Fair Value, Liabilities Measured on Recurring and Nonrecurring Basis	The following table summarizes the fair value of the 2017 Notes, 2021 Notes and 2021 PIK Notes as of December 31, 2017 and 2016 , respectively (in thousands). Fair Value at 12/31/17 Face Value at 12/31/17 Carrying value at 12/31/17 Fair Value at 12/31/16 Face Value at 12/31/16 Carrying value at 12/31/16 2017 Notes $ — $ — $ — $ 21,970 $ 22,650 $ 22,568 2021 Notes 7,306 9,427 9,821 12,192 14,177 15,228 2021 PIK Notes 198,717 263,202 271,577 177,732 243,468 248,600 $ 206,023 $ 272,629 $ 281,398 $ 211,894 $ 280,295 $ 286,396

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	The following table reconciles the face value of the 2017 Notes, 2021 Notes, 2021 PIK Notes and Term Loans to the carrying value included in the consolidated balance sheet as of December 31, 2017 and 2016 (in thousands): December 31, 2017 December 31, 2016 2017 Notes 2021 Notes 2021 PIK Notes Term Loans 2017 Notes 2021 Notes 2021 PIK Notes Term Loans Face Value $ — $ 9,427 $ 263,202 $ 30,000 $ 22,650 $ 14,177 $ 243,468 $ 10,000 Unamortized Deferred Financing Costs — (212 ) — (2,037 ) (82 ) (108 ) — (2,751 ) Excess (shortfall) Carrying Value — 606 (508 ) — — 1,159 (590 ) — Accrued PIK Interest — — 8,883 — — — 5,722 — Carrying Value $ — $ 9,821 $ 271,577 $ 27,963 $ 22,568 $ 15,228 $ 248,600 $ 7,249

Other Comprehensive Income (L33

Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2016 (in thousands): Gains and Losses on Cash Flow Hedges Change in Valuation Allowance Total Balance as of December 31, 2015 $ 947 $ — $ 947 Other comprehensive income before reclassifications: Change in fair value of derivatives (4,447 ) — (4,447 ) Income tax effect 1,654 (1,654 ) — Net of tax (2,793 ) (1,654 ) (4,447 ) Amounts reclassified from accumulated other comprehensive income: Oil and gas sales (1,811 ) — (1,811 ) Income tax effect 674 (113 ) 561 Net of tax (1,137 ) (113 ) (1,250 ) Net other comprehensive loss (3,930 ) (1,767 ) (5,697 ) Balance as of December 31, 2016 $ (2,983 ) $ (1,767 ) $ (4,750 ) The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2017 (in thousands): Gains and Losses on Cash Flow Hedges Change in Valuation Allowance Total Balance as of December 31, 2016 $ (2,983 ) $ (1,767 ) $ (4,750 ) Other comprehensive income before reclassifications: Change in fair value of derivatives 6,654 — 6,654 Income tax effect (2,475 ) 1,767 (708 ) Net of tax 4,179 1,767 5,946 Amounts reclassified from accumulated other comprehensive income: Oil and gas sales (1,461 ) — (1,461 ) Income tax effect 543 — 543 Net of tax (918 ) — (918 ) Net other comprehensive loss 3,261 1,767 5,028 Balance as of December 31, 2017 $ 278 $ — $ 278

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Deferred Taxes	An analysis of the Company’s deferred tax assets and liabilities follows (amounts in thousands): December 31, 2017 2016 Net operating loss carryforwards $ 78,541 $ 92,072 Percentage depletion carryforward 5,701 9,372 Alternative minimum tax credits — 784 Contributions carryforward and other 192 282 Temporary differences: Oil and gas properties 8,279 27,992 Asset retirement obligation 7,602 13,620 Derivatives (107 ) 1,767 Share-based compensation 1,269 1,870 Original issue discount on debt exchanges 14,429 29,646 Valuation allowance (115,906 ) (177,405 ) Deferred tax asset (liability) $ — $ —
Income Tax Reconciliation	Income tax expense (benefit) for each of the years ended December 31, 2017 , 2016 and 2015 was different than the amount computed using the federal statutory rate (35%) for the following reasons (amounts in thousands): For the Year Ended December 31, 2017 2016 2015 Amount computed using the statutory rate $ (2,655 ) $ (31,623 ) $ (102,257 ) Increase (reduction) in taxes resulting from: Impact of rate change on deferred tax 64,915 — — State & local taxes (368 ) (2,000 ) (6,477 ) Percentage depletion carryforward (66 ) (163 ) (404 ) Non-deductible stock option expense (1) 305 77 90 Share-based compensation (2) 64 707 1,317 Other (21 ) 1,415 113 Change in valuation allowance (63,123 ) 32,130 110,244 Income tax expense (benefit) $ (949 ) $ 543 $ 2,626 (1) Relates to compensation expense related to Incentive Stock Options. (2) Relates to the write-off of deferred tax assets associated with share-based compensation that will not be deductible for tax purposes.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Lease Commitments	Future minimum lease commitments as of December 31, 2017 under these operating leases are as follows (in thousands): 2018 $ 1,278 2019 1,242 2020 1,175 2021 447 2022 433 Thereafter 392 $ 4,967

Supplementary Information on 36

Supplementary Information on Oil and Gas Operations—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Costs incurred in oil and gas property acquisition	The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are located onshore and offshore in the continental United States: Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities ( amounts in thousands ) For the Year-Ended December 31, 2017 2016 2015 Acquisition costs: Proved $ 1,330 $ 3,346 $ 2,287 Unproved (1) 12,762 2,197 2,550 Divestiture of proved leasehold (4,795 ) (7,000 ) — Exploration costs: Proved 9,466 715 29,322 Unproved (287 ) 603 7,677 Development costs 32,622 1,522 9,888 Capitalized general and administrative and interest costs 8,269 7,558 12,881 Total costs incurred $ 59,367 $ 8,941 $ 64,605 For the Year-Ended December 31, 2017 2016 2015 Accumulated depreciation, depletion and amortization (DD&A) Balance, beginning of year $ (1,243,286 ) $ (1,157,455 ) $ (1,648,060 ) Provision for DD&A (31,667 ) (27,962 ) (62,138 ) Ceiling test writedown — (40,304 ) (266,562 ) Sale of proved properties and other (2) (3) (10,707 ) (17,565 ) 819,305 Balance, end of year $ (1,285,660 ) $ (1,243,286 ) $ (1,157,455 ) DD&A per Mcfe $ 1.15 $ 1.19 $ 1.82 (1) During 2017 , the Company acquired approximately 24,600 gross acres for approximately $9.3 million of cash and 2.0 million shares of common stock. (2) During 2015 , the Company sold its Woodford Shale and Mississippian Lime assets for an aggregate cash purchase price of $274.1 million (see Note 2). (3) During 2017 , the Company sold its East Lake Verret assets for net proceeds of approximately $2.2 million and its East Texas saltwater disposal assets for net proceeds of $8.5 million . During 2016 , the Company sold its remaining Oklahoma producing assets for an aggregate purchase price of $17.6 million . During 2015 , the Company sold its Fort Trinidad assets for net proceeds of approximately $0.5 million and its East Haynesville assets for net proceeds of approximately $0.1 million .
Schedule of proved developed reserve quantities	The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil (including condensate), gas and natural gas liquid reserves, all located onshore and offshore in the continental United States: Oil NGL Natural Gas Total Proved reserves as of December 31, 2014 2,437 73,498 309,025 397,148 Revisions of previous estimates (211 ) (3,571 ) (9,852 ) (14,698 ) Extensions, discoveries and other additions 163 16,078 45,645 62,702 Sale of reserves in place (54 ) (45,692 ) (186,972 ) (232,988 ) Production (529 ) (5,487 ) (25,502 ) (34,160 ) Proved reserves as of December 31, 2015 1,806 34,826 132,344 178,004 Revisions of previous estimates 247 (4,380 ) (11,854 ) (14,748 ) Extensions, discoveries and other additions — — 1,485 1,485 Sale of reserves in place (154 ) — (24,834 ) (25,759 ) Production (502 ) (3,871 ) (16,617 ) (23,501 ) Proved reserves as of December 31, 2016 1,397 26,575 80,524 115,481 Revisions of previous estimates 308 (7,269 ) 381 (5,040 ) Extensions, discoveries and other additions 777 4,565 64,704 73,931 Purchase of producing properties 48 — 473 761 Sale of reserves in place (90 ) — (1,033 ) (1,573 ) Production (592 ) (4,450 ) (19,611 ) (27,613 ) Proved reserves as of December 31, 2017 1,848 19,421 125,438 155,947 Proved developed reserves As of December 31, 2015 1,549 15,792 78,533 103,615 As of December 31, 2016 1,212 13,073 47,349 67,694 As of December 31, 2017 1,078 12,564 57,409 76,441 Proved undeveloped reserves As of December 31, 2015 257 19,034 53,811 74,389 As of December 31, 2016 185 13,502 33,175 47,787 As of December 31, 2017 770 6,857 68,029 79,506
Standardized measure of discounted future cash flows	Standardized Measure December 31, 2017 2016 2015 Future cash flows $ 539,244 $ 299,035 $ 487,834 Future production costs (184,171 ) (117,283 ) (171,678 ) Future development costs (128,447 ) (83,720 ) (116,591 ) Future income taxes — — — Future net cash flows 226,626 98,032 199,565 10% annual discount (99,329 ) (30,763 ) (71,880 ) Standardized measure of discounted future net cash flows $ 127,297 $ 67,269 $ 127,685
Schedule of changes in standardized measure of discounted future net cash flows	Changes in Standardized Measure Year Ended December 31, 2017 2016 2015 Standardized measure at beginning of year $ 67,269 $ 127,685 $ 548,562 Sales and transfers of oil and gas produced, net of production costs (70,362 ) (35,993 ) (55,849 ) Changes in price, net of future production costs 53,516 (30,427 ) (267,710 ) Extensions and discoveries, net of future production and development costs 50,977 864 70,928 Changes in estimated future development costs, net of development costs incurred during this period 17,144 26,356 31,007 Revisions of quantity estimates (7,482 ) (14,889 ) (14,427 ) Accretion of discount 6,727 12,769 60,071 Net change in income taxes — — 52,149 Purchase of reserves in place 549 — — Sale of reserves in place (1,305 ) (16,701 ) (194,454 ) Changes in production rates (timing) and other 10,264 (2,395 ) (102,592 ) Net increase (decrease) in standardized measure 60,028 (60,416 ) (420,877 ) Standardized measure at end of year $ 127,297 $ 67,269 $ 127,685
Average sales price and average production costs	The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were: 2017 2016 2015 Oil, $/Bbl $52.49 $40.85 $50.29 Ngls, $/Mcfe 3.23 2.40 2.24 Natural Gas, $/Mcf 3.03 1.82 2.41

Summarized Quarterly Financia37

Summarized Quarterly Financial Information - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Summarized quarterly financial information is as follows (amounts in thousands except per share data): Quarter Ended March 31 June 30 September 30 December 31 2017 Revenues $ 20,772 $ 24,251 $ 28,184 $ 35,080 Income (loss) from operations (3,633 ) (2,289 ) (1,885 ) 221 Loss available to common stockholders (4,918 ) (3,385 ) (3,085 ) $ (389 ) Loss per share: Basic $ (0.23 ) $ (0.16 ) $ (0.15 ) $ (0.02 ) Diluted $ (0.23 ) $ (0.16 ) $ (0.15 ) $ (0.02 ) 2016: Revenues $ 17,320 $ 15,824 $ 17,094 $ 16,429 Loss from operations (1) (37,557 ) (22,383 ) (22,039 ) (8,374 ) Loss available to common stockholders (1) (39,137 ) (24,143 ) (23,306 ) (9,659 ) Loss per share: Basic $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) Diluted $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) 2016 included pretax ceiling test write-downs of $18.9 million , $12.8 million and $8.7 million , respectively.

Organization and Summary of S38

Organization and Summary of Significant Accounting Policies - Other Property and Equipment (Details) - Furniture and Fixtures	12 Months Ended
	Dec. 31, 2017
Minimum
Property, Plant and Equipment [Line Items]
Useful life (in years)	3 years
Maximum
Property, Plant and Equipment [Line Items]
Useful life (in years)	5 years

Organization and Summary of S39

Organization and Summary of Significant Accounting Policies - Revenues (Details) - Oil and Gas Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Superior Natural Gas
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	29.00%	14.00%
Shell Trading Company
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	24.00%	23.00%	18.00%
Shell Trading Company
Concentration Risk [Line Items]
Net oil and gas revenues (percent)		17.00%	21.00%
BG Group
Concentration Risk [Line Items]
Net oil and gas revenues (percent)		10.00%	10.00%
Unimark, LLC
Concentration Risk [Line Items]
Net oil and gas revenues (percent)			17.00%

Organization and Summary of S40

Organization and Summary of Significant Accounting Policies - Other Assets (Details) - USD ($) $ in Thousands	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deposit for surety bonds		$ 8,300	$ 0
Gulf of Mexico Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deposit for surety bonds		$ 8,300
Subsequent Event | Gulf of Mexico Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase commitment	$ 3,800
Other Noncurrent Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deposit for surety bonds			$ 6,200

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) $ in Thousands, shares in Millions, Mcfe in Billions

Dec. 20, 2017USD ($)a

Jun. 04, 2015USD ($)

Jan. 31, 2018USD ($)

Dec. 31, 2017USD ($)shares

Dec. 31, 2016USD ($)

Mar. 31, 2016USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)Mcfe

Dec. 15, 2017USD ($)

Apr. 17, 2017USD ($)

Oct. 31, 2016USD ($)

Apr. 20, 2016USD ($)

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Other receivable

$ 7,750

$ 0

$ 7,750

$ 0

Gain on sale of assets

0

0

$ 21,937

Sale of oil and gas properties

10,707

25,482

$ 271,769

Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties

248

3,419

Deposit for surety bonds

8,300

0

8,300

0

Woodford And Mississippian Lime

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Consideration received from sale

$ 280,000

Cash received from sale

257,700

Other receivable

$ 13,900

Proved reserves | Mcfe

227.2

Estimated proved reserves attributable to Sold Assets (percent of total)

57.00%

Sale of oil and gas properties, significant alteration threshold percent

25.00%

Gain on sale of assets

23,200

Sale of oil and gas properties

274,100

Woodford Shale Assets (East Hoss Assets)

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Consideration received from sale

$ 18,000

Oklahoma Assets

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Consideration received from sale

$ 700

Sale of oil and gas properties

17,600

Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties

$ 3,300

Interests in East Lake Verret Field

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Consideration received from sale

$ 2,200

Saltwater Disposal Assets in East Texas

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Consideration received from sale

$ 8,500

Gulf of Mexico Properties

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Cash collateral, refund receivable

10,700

10,700

Deposit for surety bonds

$ 8,300

$ 8,300

East Texas

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Sale of oil and gas properties

$ 7,000

Payments to repurchase certain non-producing assets

$ 5,000

Austin Chalk Acreage

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Acres acquired | a

24,600

Purchase price

$ 9,300

Common shares issued in connection with acquisition | shares

2

Subsequent Event | Gulf of Mexico Properties

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Purchase commitment

$ 3,800

Pro Forma | Subsequent Event | Gulf of Mexico Properties

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties

$ 28,400

Equity - Common Stock (Details)

Equity - Common Stock (Details) shares in Thousands	May 18, 2016shares	Dec. 31, 2017shares	Dec. 31, 2016shares	May 17, 2016shares
Class of Stock [Line Items]
Common stock, shares outstanding		25,521	21,197
Common Stock
Class of Stock [Line Items]
Reverse stock split, conversion ratio	0.25
Common stock, shares outstanding	17,600			70,500
Austin Chalk Acreage
Class of Stock [Line Items]
Common shares issued in connection with acquisition		2,000

Equity - Convertible Preferred

Equity - Convertible Preferred Stock (Details)	12 Months Ended
	Dec. 31, 2017USD ($)payment$ / sharesRateshares	Dec. 31, 2016shares
Class of Stock [Line Items]
Preferred stock, shares outstanding	1,495,000	1,495,000
Series B Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares outstanding	1,495,000
Series B cumulative convertible perpetual preferred stock interest rate | Rate	6.875%
Number of deferred dividend payments | payment	7
Dividends payable | $	$ 10,300,000
Number of trading days	20 days
Number of consecutive trading days	30 years
Closing price as percentage of conversion price	130.00%
Series B Preferred Stock converted into common stock (in shares)	0.860825
Initial conversion price of common stock (in usd per share) | $ / shares	$ 58.08
Trading day averaging period for determining conversion value	20 days
Conversion rate numerator for Preferred Stock | $	$ 50

Earnings Per Share - Reconcilia

Earnings Per Share - Reconciliation Between Basic and Diluted EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
A reconciliation between basic and diluted earnings per share computations
Net loss available to common stockholders	$ (389)	$ (3,085)	$ (3,385)	$ (4,918)	$ (9,659)	$ (23,306)	$ (24,143)	$ (39,137)	$ (11,776)	$ (96,245)	$ (299,929)
Net loss available to common stockholders (in shares)									21,330	18,354	16,256
Net loss available to common stockholders (in usd per share)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (0.55)	$ (5.24)	$ (18.45)
Stock options, effect of dilutive securities									$ 0	$ 0
Stock options, effect of dilutive securities, (in shares)									0	0
Attributable to participating securities									$ 0	$ 0
Restricted stock, effect of dilutive securities (in shares)									0	0	0
DILUTED EPS, Loss									$ (11,776)	$ (96,245)	$ (299,929)
DILUTED EPS (in shares)									21,330	18,354	16,256
DILUTED EPS, per share amount (in usd per share)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (0.55)	$ (5.24)	$ (18.45)

Earnings Per Share - Additional

Earnings Per Share - Additional Information (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock issuable on conversion (in shares)	1.6	0.9	0.1
Convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock issuable on conversion (in shares)	1.3	1.3	1.3

Share-Based Compensation - Shar

Share-Based Compensation - Share based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of share-based compensation
Share-based compensation	$ 1,649	$ 1,687	$ 4,178
Incentive Stock Options (share settled)
Summary of share-based compensation
Share-based compensation	820	206	243
Non-Qualified Stock Options (share settled)
Summary of share-based compensation
Share-based compensation	387	164	71
Restricted stock (share settled)
Summary of share-based compensation
Share-based compensation	197	1,073	4,303
Cash settled stock units
Summary of share-based compensation
Share-based compensation	$ 245	$ 244	$ (439)

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details)	1 Months Ended	12 Months Ended
	Nov. 30, 2014shares	Dec. 31, 2017USD ($)company$ / sharesshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation costs capitalized in period | $		$ 100,000	$ 100,000	$ 0
Tax benefit from compensation expense | $		300,000	500,000	1,500,000
Total compensation cost not yet recognized | $		$ 3,900,000
Period for recognition		3 years
Fair value of stock options that vested during period | $		$ 1,600,000	400,000	$ 800,000
Granted (in shares)		1,159,856
Vested/Paid (in shares)		(39,168)
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in dollars per share) | $ / shares		$ 1.87		$ 5.08
Period until vesting		1 year
Granted (in shares)		487,502
Total value of stock that vested | $		$ 1,300,000	2,400,000	$ 4,700,000
Vested/Paid (in shares)		(78,557)
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		3 years
Period until vesting		1 year
Award expiration period		10 years
Cash settled stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		3 years
Granted (in shares)		889,587
Total value of stock that vested | $		$ 100,000	$ 300,000
Vested/Paid (in shares)		(31,703)	(111,461)
Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual vesting percentage		33.33%
Granted (in shares)	60,767	270,269
Evaluation period (in days)		20 days
Number of peer group companies | company		12
Earned at end of performance period, percent			50.00%
Vested/Paid (in shares)		(7,465)
Restricted Stock Units (RSUs) And Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred compensation share-based arrangements, liability, current | $		$ 300,000	$ 100,000
Prior to 2011 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual vesting percentage		25.00%
Minimum | Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earning percentage		0.00%
Maximum | Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earning percentage		200.00%

Share-Based Compensation - Fair

Share-Based Compensation - Fair Value Assumption (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Stock options granted (shares)	219,130
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Dividend yield	0.00%	0.00%
Expected volatility	80.44%
Risk-free rate	1.925%
Expected term	6 years	6 years
Stock options granted (shares)	219,130	1,168,754
Weighted average grant date fair value (usd per share)	$ 1.28	$ 1.96
Fair value of grants	$ 280	$ 2,293
Minimum | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility		62.00%
Risk-free rate		1.255%
Maximum | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility		79.99%
Risk-free rate		2.09%

Share-Based Compensation - Acti

Share-Based Compensation - Activity (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Number of Options
Outstanding at beginning of year (in shares) | shares	1,412,940
Granted (in shares) | shares	219,130
Expired/canceled/forfeited (in shares) | shares	(23,424)
Exercised (in shares) | shares	0
Outstanding at end of year (in shares) | shares	1,608,646
Wgtd. Avg. Exercise Price
Outstanding at beginning of year (in dollars per share) | $ / shares	$ 7.13
Granted (in dollars per share) | $ / shares	1.85
Expired/canceled/forfeited (in dollars per share) | $ / shares	21.49
Exercised (in dollars per share) | $ / shares
Outstanding at end of year (in dollars per share) | $ / shares	$ 6.20
Additional Disclosures
Options exercisable at end of year (in shares) | shares	705,594
Options expected to vest (in shares) | shares	1,563,493
Options exercisable at end of year (usd per share) | $ / shares	$ 10.34
Options expected to vest (usd per share) | $ / shares	$ 6.29
Outstanding, remaining contractual term	8 years 29 days
Exercisable, remaining contractual term	7 years
Vested and expected to vest, remaining contractual term	8 years 22 days
Outstanding, intrinsic value | $	$ 9
Exercisable, intrinsic value | $	0
Vested and expected to vest, intrinsic value | $	$ 8

Share-Based Compensation - Exer

Share-Based Compensation - Exercise Prices (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding at end of year (in shares)	1,608,646	1,412,940
Wgtd. Avg. Remaining Contractual Life	8 years 29 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 6.20	$ 7.13
Options exercisable (in shares)	705,594
Wgtd. Avg. Exercise Price (usd per share)	$ 10.34
$0.00-$2.49
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	0
Exercise price range, upper range limit	$ 2.49
Outstanding at end of year (in shares)	285,503
Wgtd. Avg. Remaining Contractual Life	9 years 5 months 23 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 1.97
Options exercisable (in shares)	22,150
Wgtd. Avg. Exercise Price (usd per share)	$ 2.37
$2.50-$3.49
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	2.50
Exercise price range, upper range limit	$ 3.49
Outstanding at end of year (in shares)	878,833
Wgtd. Avg. Remaining Contractual Life	8 years 8 months 27 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 3.17
Options exercisable (in shares)	362,973
Wgtd. Avg. Exercise Price (usd per share)	$ 3.17
$3.50-$4.99
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	3.50
Exercise price range, upper range limit	$ 4.99
Outstanding at end of year (in shares)	206,769
Wgtd. Avg. Remaining Contractual Life	8 years 4 months 17 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 4.26
Options exercisable (in shares)	82,930
Wgtd. Avg. Exercise Price (usd per share)	$ 4.23
$15.00-$30.32
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	15
Exercise price range, upper range limit	$ 30.32
Outstanding at end of year (in shares)	237,541
Wgtd. Avg. Remaining Contractual Life	3 years 8 months 16 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 24.18
Options exercisable (in shares)	237,541
Wgtd. Avg. Exercise Price (usd per share)	$ 24.18

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Number of Shares
Outstanding at beginning of year (in shares)	46,908
Granted (in shares)	1,159,856
Canceled/forfeited (in shares)	(276)
Lapse of restrictions (in shares)	(39,168)
Outstanding at end of year (in shares)	1,167,320	46,908
Restricted Stock
Number of Shares
Outstanding at beginning of year (in shares)	78,557
Granted (in shares)	487,502
Lapse of restrictions (in shares)	(78,557)
Outstanding at end of year (in shares)	487,502	78,557
Wgtd. Avg. Fair Value per Share
Outstanding at beginning of year (in dollars per share)	$ 16.57
Granted (in dollars per share)	1.87		$ 5.08
Lapse of restrictions (in dollars per share)	16.57
Outstanding at end of year (in dollars per share)	$ 1.87	$ 16.57
Additional Information
Total value of stock that vested	$ 1.3	$ 2.4	$ 4.7

Share-Based Compensation - Re52

Share-Based Compensation - Restricted Stock Units (Details) - shares	1 Months Ended	12 Months Ended
	Nov. 30, 2014	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Outstanding at beginning of year (in shares)		46,908
Granted (in shares)		1,159,856
Canceled/forfeited (in shares)		(276)
Vested/Paid (in shares)		(39,168)
Outstanding at end of year (in shares)		1,167,320	46,908
MRSU
Number of Shares
Outstanding at beginning of year (in shares)		14,929
Granted (in shares)	60,767	270,269
Canceled/forfeited (in shares)		0
Vested/Paid (in shares)		(7,465)
Outstanding at end of year (in shares)		277,733	14,929
RSU
Number of Shares
Outstanding at beginning of year (in shares)		31,979
Granted (in shares)		889,587
Canceled/forfeited (in shares)		(276)
Vested/Paid (in shares)		(31,703)	(111,461)
Outstanding at end of year (in shares)		889,587	31,979

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 36,610	$ 42,556
Liabilities incurred	574	0
Liabilities settled	(3,364)	(3,296)
Accretion expense	2,252	2,515
Revisions in estimated cash flows	(4,514)	(1,746)
Divestiture of oil and gas properties	(248)	(3,419)
Asset retirement obligation, end of period	31,310	36,610
Less: current portion of asset retirement obligation	(687)	(4,160)
Long-term asset retirement obligation	$ 30,623	32,450
Oklahoma Assets
Changes to the Company's asset retirement obligation liability
Divestiture of oil and gas properties		$ (3,300)

Derivative Instruments - Volume

Derivative Instruments - Volumes and Weighted Average Price (Details) - Swap	12 Months Ended
	Dec. 31, 2017MMBTUMBbls$ / shares
Natural Gas | January 2018 - March 2018
Oil and gas contracts
Daily Volumes | MMBTU	35,000
Weighted Average Price	$ 3.24
Crude Oil | January 2018 - December 2018
Oil and gas contracts
Daily Volumes | MBbls	0.250
Weighted Average Price	$ 55

Derivative Instruments - Effect

Derivative Instruments - Effect of Cash Flow Hedges on the Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative asset	$ 400
Designated as Hedging Instrument | Commodity Derivatives | Derivative asset
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative asset	1,174
Designated as Hedging Instrument | Commodity Derivatives | Derivative liability
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative liability	$ (731)	$ (3,947)
Designated as Hedging Instrument | Commodity Derivatives | Other long-term liabilities
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative liability		$ (803)

Derivative Instruments - Effe56

Derivative Instruments - Effect of Cash Flow Hedges on the Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income	$ 5,028	$ (5,697)	$ (4,473)
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income	6,654	(4,447)	9,991
Designated as Hedging Instrument | Oil and gas sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain Reclassified into Income	$ 1,461	$ 1,811	$ 17,114

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative asset	$ 0.4
Realization of gain, net of taxes	0.3
Gas hedges
Derivatives, Fair Value [Line Items]
Net settlement of hedges	$ 1.5	$ 1.8	$ 15.9
NGL hedges
Derivatives, Fair Value [Line Items]
Net settlement of hedges			0.5
Crude Oil
Derivatives, Fair Value [Line Items]
Net settlement of hedges			$ 0.6

Fair Value Measurements - Commo

Fair Value Measurements - Commodity Derivatives at Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Quoted Prices in Active Markets (Level 1)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	$ 0	$ 0
Significant Other Observable Inputs (Level 2)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	443	(4,750)
Significant Unobservable Inputs (Level 3)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	$ 0	$ 0

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value and Carrying Value (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Jul. 03, 2013	Aug. 19, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	$ 272,629,000	$ 280,295,000
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	206,023,000	211,894,000
Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	281,398,000	286,396,000
Senior Notes | 2017 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	0	22,650,000	$ 200,000,000	$ 150,000,000
Senior Notes | 2017 Notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	0	21,970,000
Senior Notes | 2017 Notes | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	0	22,568,000
Senior Notes | 2021 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	9,427,000	14,177,000
Senior Notes | 2021 Notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	7,306,000	12,192,000
Senior Notes | 2021 Notes | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	9,821,000	15,228,000
Payment in Kind (PIK) Note | 2021 PIK Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	263,202,000	243,468,000
Payment in Kind (PIK) Note | 2021 PIK Notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	198,717,000	177,732,000
Payment in Kind (PIK) Note | 2021 PIK Notes | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 271,577,000	$ 248,600,000

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) shares in Millions	Dec. 28, 2017USD ($)shares	Mar. 31, 2017USD ($)	Oct. 17, 2016USD ($)	Sep. 27, 2016USD ($)paymentshares	Feb. 17, 2016USD ($)shares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2017	Jun. 30, 2017	Jan. 14, 2016	Jul. 03, 2013USD ($)	Aug. 19, 2010USD ($)
Debt Instrument [Line Items]
Principal amount						$ 272,629,000	$ 280,295,000
Gain (loss) on extinguishment of debt						403,000	0	$ 0
Amortization of debt issuance costs						0	(10,139,000)	$ 0
10% Senior Unsecured Notes Due 2017
Debt Instrument [Line Items]
Repayments of debt		$ 22,800,000
10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Principal amount						$ 0	$ 22,650,000					$ 200,000,000	$ 150,000,000
Stated interest rate (as a percent)						10.00%	10.00%					10.00%	10.00%
Long-term debt					$ 135,600,000	$ 0	$ 22,568,000
Excess (shortfall) carrying value						0	0
Deferred finance costs						0	(82,000)
10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Debt extinguished	$ 4,800,000
Common shares issued related to extinguishment of debt | shares	2.2
10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Principal amount						$ 9,427,000	14,177,000
Stated interest rate (as a percent)						10.00%
Long-term debt						$ 9,821,000	15,228,000
Excess (shortfall) carrying value						606,000	1,159,000
Deferred finance costs						(212,000)	(108,000)
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Principal amount						$ 263,202,000	243,468,000
Stated interest rate (as a percent)						10.00%
Long-term debt						$ 271,577,000	248,600,000
Excess (shortfall) carrying value						(508,000)	(590,000)
Deferred finance costs						0	0
Private Exchange Offer and Consent Solicitation
Debt Instrument [Line Items]
Repayments of debt					53,600,000
Private Exchange Offer and Consent Solicitation | 10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Debt conversion, original debt, amount					$ 214,400,000
Debt conversion, original debt, percent of total					61.00%
Gain (loss) on extinguishment of debt					$ 0
Private Exchange Offer and Consent Solicitation | 10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate (as a percent)											10.00%
Debt conversion, converted instrument, amount					144,700,000
Long-term debt					$ 13,900,000
Amortization of debt issuance costs						(600,000)
Private Exchange Offer and Consent Solicitation | 10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate (as a percent)									10.00%
Excess (shortfall) carrying value				$ (600,000)		500,000
Amortization of debt issuance costs						(100,000)
September Exchange And Consent Solicitation | 10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Debt conversion, original debt, amount				$ 113,000,000
Debt conversion, original debt, percent of total				83.00%
Long-term debt				$ 22,700,000
September Exchange And Consent Solicitation | 10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Debt conversion, original debt, amount				$ 130,500,000
Debt conversion, original debt, percent of total				90.00%
Long-term debt				$ 14,200,000
September Exchange And Consent Solicitation | 10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Debt conversion, converted instrument, amount				$ 243,500,000
Number of interest payments with variable rate | payment				3
September Exchange And Consent Solicitation | 10% Senior Secured PIK Notes due 2021 | PIK Interest | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate (as a percent)				1.00%
Adjusted LIBO rate (as a percent)				9.00%
Common Stock | Private Exchange Offer and Consent Solicitation
Debt Instrument [Line Items]
Debt conversion, converted instrument, shares issued | shares				3.5	1.1
Term Loan | Line of Credit
Debt Instrument [Line Items]
Principal amount						30,000,000	10,000,000
Long-term debt						27,963,000	7,249,000
Excess (shortfall) carrying value						0	0
Deferred finance costs						(2,037,000)	$ (2,751,000)
Term Loan | Loan Agreement | Line of Credit
Debt Instrument [Line Items]
Stated interest rate (as a percent)			10.00%
Long-term debt						$ 30,000,000
Revolving credit facility			$ 50,000,000
Borrowing availability period			3 years
First priority lien as percent of total value of oil and gas properties			90.00%
Present value of estimated future net revenues, discount percent			10.00%
Ratio of present value of estimated future net revenues to sum of outstanding term loans and commitments										2

Long-Term Debt - Face Value to

Long-Term Debt - Face Value to Carrying Value Reconciliation (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Feb. 17, 2016	Jul. 03, 2013	Aug. 19, 2010
Debt Instrument [Line Items]
Principal amount	$ 272,629,000	$ 280,295,000
Senior Notes | 10% Senior Unsecured Notes Due 2017
Debt Instrument [Line Items]
Principal amount	0	22,650,000		$ 200,000,000	$ 150,000,000
Unamortized deferred finance costs	0	(82,000)
Excess (shortfall) Carrying Value	0	0
Long-term debt	0	22,568,000	$ 135,600,000
Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Principal amount	9,427,000	14,177,000
Unamortized deferred finance costs	(212,000)	(108,000)
Excess (shortfall) Carrying Value	606,000	1,159,000
Long-term debt	9,821,000	15,228,000
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Principal amount	263,202,000	243,468,000
Unamortized deferred finance costs	0	0
Excess (shortfall) Carrying Value	(508,000)	(590,000)
Accrued PIK Interest	8,883,000	5,722,000
Long-term debt	271,577,000	248,600,000
Term Loan | Line of Credit
Debt Instrument [Line Items]
Principal amount	30,000,000	10,000,000
Unamortized deferred finance costs	(2,037,000)	(2,751,000)
Excess (shortfall) Carrying Value	0	0
Long-term debt	$ 27,963,000	$ 7,249,000

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)party	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Related Party Transaction [Line Items]
Total joint interest billing receivable (less than 1%)	1.00%
Officer
Related Party Transaction [Line Items]
Number of related parties | party	2
Joint interest billing receivables	$ 89
Mr. Goodson | Officer
Related Party Transaction [Line Items]
Proceeds from affiliates	(107)	$ (15)	$ (45)
Mr. Green | Officer
Related Party Transaction [Line Items]
Payments of distributions to related parties	$ 41	$ 25	$ 30

Ceiling Test Write-down (Detail

Ceiling Test Write-down (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)$ / mcf$ / Mcfe$ / bbl	Dec. 31, 2015USD ($)$ / mcf$ / Mcfe$ / bbl
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Rate for discounting future cash flows	10.00%
Ceiling test write-down	$ 0	$ 40,304	$ 266,562
Mcf of natural gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices (usd per unit) | $ / mcf		2.51	2.42
Barrel of oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices (usd per unit) | $ / bbl		40.85	50.29
Mcfe of natural gas liquids
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices (usd per unit) | $ / Mcfe		1.82	2.21
Cash Flow Hedging | Commodity Contract
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Ceiling test write-downs decrease		$ 8,000	$ 1,100

Other Comprehensive Income (L64

Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ (251,095)	$ (163,067)	$ 136,909
Other comprehensive income before reclassifications:
Change in fair value of derivatives	6,654	(4,447)
Income tax effect	(708)	0
Net of tax	5,946	(4,447)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,461)	(1,811)
Income tax effect	543	561
Net of tax	(918)	(1,250)
Net other comprehensive loss	5,028	(5,697)
Ending balance	(248,935)	(251,095)	(163,067)
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(2,983)	947	5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	6,654	(4,447)	9,991
Income tax effect	(2,475)	1,654	(3,716)
Net of tax	4,179	(2,793)	6,275
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,461)	(1,811)	(17,114)
Income tax effect	543	674	6,366
Net of tax	(918)	(1,137)	(10,748)
Net other comprehensive loss	3,261	(3,930)	(4,473)
Ending balance	278	(2,983)	947
Change in Valuation Allowance
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(1,767)	0
Other comprehensive income before reclassifications:
Change in fair value of derivatives	0	0
Income tax effect	1,767	(1,654)
Net of tax	1,767	(1,654)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	0	0
Income tax effect	0	(113)
Net of tax	0	(113)
Net other comprehensive loss	1,767	(1,767)
Ending balance	0	(1,767)	0
Total
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(4,750)	947	5,420
Amounts reclassified from accumulated other comprehensive income:
Ending balance	$ 278	$ (4,750)	$ 947

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes (Textual) [Abstract]
Income taxes at a statutory rate		35.00%	35.00%
Cumulative loss period	3 years
Valuation allowance	$ 115,906	$ 177,405
Tax Cuts and Jobs Act, provisional Income tax expense (benefit)	64,900
Deferred tax assets, operating loss carryforwards	78,541	$ 92,072
Operating loss carryforwards	332,100
Operating loss carryforwards subject to expiration	6,900
Depletion Deduction
Income Taxes (Textual) [Abstract]
Depletion deduction carryforward	26,900
Louisiana
Income Taxes (Textual) [Abstract]
Operating loss carryforwards	139,400
Operating loss carryforwards subject to expiration	3,200
Accounting Standards Update 2016-09
Income Taxes (Textual) [Abstract]
Deferred tax assets, operating loss carryforwards	$ 4,700

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 78,541	$ 92,072
Percentage depletion carryforward	5,701	9,372
Alternative minimum tax credits	0	784
Contributions carryforward and other	192	282
Oil and gas properties	8,279	27,992
Asset retirement obligation	7,602	13,620
Derivatives	(107)
Deferred Tax Assets, Derivative Instruments		1,767
Share-based compensation	1,269	1,870
Original issue discount on debt exchanges	14,429	29,646
Valuation allowance	(115,906)	(177,405)
Deferred tax asset (liability)	$ 0	$ 0

Income Taxes - Income Tax Expen

Income Taxes - Income Tax Expense (Benefit) Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Amount computed using the statutory rate	$ (2,655)	$ (31,623)	$ (102,257)
Impact of rate change on deferred tax	64,915	0	0
State & local taxes	(368)	(2,000)	(6,477)
Percentage depletion carryforward	(66)	(163)	(404)
Non-deductible stock option expense	305	77	90
Share-based compensation	64	707	1,317
Other	(21)	1,415	113
Change in valuation allowance	(63,123)	32,130	110,244
Income tax expense (benefit)	$ (949)	$ 543	$ 2,626

Commitments and Contingencies68

Commitments and Contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	$ 1,278
2,019	1,242
2,020	1,175
2,021	447
2,022	433
Thereafter	392
Total	4,967
Operating leases rent expense	$ 1,500	$ 1,500	$ 1,700

Supplementary Information on 69

Supplementary Information on Oil and Gas Operations—Unaudited - Costs Incurred (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / Mcfe	Dec. 31, 2016USD ($)$ / Mcfe	Dec. 31, 2015USD ($)$ / Mcfe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Acquisition costs: Proved	$ 1,330	$ 3,346	$ 2,287
Acquisition costs: Unproved	12,762	2,197	2,550
Divestiture of proved leasehold	(4,795)	(7,000)	0
Exploration costs: Proved	9,466	715	29,322
Exploration costs: Unproved	(287)	603	7,677
Development costs	32,622	1,522	9,888
Capitalized general and administrative and interest costs	8,269	7,558	12,881
Total costs incurred	59,367	8,941	64,605
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	(1,243,286)	(1,157,455)	(1,648,060)
Provision for DD&A	(31,667)	(27,962)	(62,138)
Ceiling test writedown	0	(40,304)	(266,562)
Sale of proved properties and other	(10,707)	(17,565)	819,305
Balance, end of year	$ (1,285,660)	$ (1,243,286)	$ (1,157,455)
DD&A per Mcfe (usd per mcfe) | $ / Mcfe	1.15	1.19	1.82

Supplementary Information on 70

Supplementary Information on Oil and Gas Operations—Unaudited - Investment in Oil and Gas Properties (Details) $ in Thousands, shares in Millions	Dec. 20, 2017USD ($)a	Dec. 31, 2017USD ($)Wellsshares	Dec. 31, 2017USD ($)Wells	Dec. 31, 2016USD ($)Wells	Dec. 31, 2015USD ($)	Oct. 31, 2016USD ($)	Jun. 04, 2015USD ($)
Reserve Quantities [Line Items]
Sale of oil and gas properties			$ 10,707	$ 25,482	$ 271,769
Unevaluated oil and gas properties		$ 21,900	21,900	9,000
Interest costs capitalized			$ 1,600	900	4,700
Expected period to evaluate existing unevaluated properties			3 years
Unevaluated costs expected to be evaluated in 2017		4,100	$ 4,100
Fort Trinidad
Reserve Quantities [Line Items]
Sale of oil and gas properties					500
East Haynesville
Reserve Quantities [Line Items]
Sale of oil and gas properties					100
Uncompleted Wells Equipment and Facilities
Reserve Quantities [Line Items]
Unevaluated oil and gas properties		$ 700	$ 700	$ 400
Exploratory wells drilled, unevaluated | Wells		2	2	1
Incurred In 2017
Reserve Quantities [Line Items]
Unevaluated oil and gas properties		$ 14,600	$ 14,600
Percentage of unevaluated costs capitalized in period		67.00%	67.00%
Incurred In 2016
Reserve Quantities [Line Items]
Unevaluated oil and gas properties				$ 2,000
Percentage of unevaluated costs capitalized in period				9.00%
Incurred Prior 2016
Reserve Quantities [Line Items]
Unevaluated oil and gas properties					$ 5,200
Percentage of unevaluated costs capitalized in period					24.00%
Austin Chalk Acreage
Reserve Quantities [Line Items]
Acres acquired | a	24,600
Purchase price	$ 9,300
Common shares issued in connection with acquisition | shares		2
Woodford And Mississippian Lime
Reserve Quantities [Line Items]
Sale of oil and gas properties			$ 274,100
Consideration received from sale							$ 280,000
Oklahoma Assets
Reserve Quantities [Line Items]
Sale of oil and gas properties				$ 17,600
Consideration received from sale						$ 700
Gulf of Mexico Properties
Reserve Quantities [Line Items]
Unevaluated oil and gas properties		$ 5,500	$ 5,500
Percentage of unevaluated costs capitalized in period		25.00%	25.00%

Supplementary Information on 71

Supplementary Information on Oil and Gas Operations—Unaudited - Proved Reserves (Details) Mcfe in Thousands, MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2017McfeMBblsMMcf	Dec. 31, 2016McfeMBblsMMcf	Dec. 31, 2015McfeMBblsMMcf
Oil
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MBbls	1,397	1,806	2,437
Revisions of previous estimates | MBbls	308	247	(211)
Extensions, discoveries and other additions | MBbls	777	0	163
Purchase of producing properties | MBbls	48
Sale of reserves in place | MBbls	(90)	(154)	(54)
Production | MBbls	(592)	(502)	(529)
Proved reserves ending balance | MBbls	1,848	1,397	1,806
Proved developed reserves | MBbls	1,078	1,212	1,549
Proved undeveloped reserve | MBbls	770	185	257
Mcfe of natural gas liquids
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	26,575	34,826	73,498
Revisions of previous estimates	(7,269)	(4,380)	(3,571)
Extensions, discoveries and other additions	4,565	0	16,078
Purchase of producing properties	0
Sale of reserves in place	0	0	(45,692)
Production	(4,450)	(3,871)	(5,487)
Proved reserves, ending balance	19,421	26,575	34,826
Proved undeveloped reserve	12,564	13,073	15,792
Proved developed reserves	6,857	13,502	19,034
Natural Gas
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MMcf	80,524	132,344	309,025
Revisions of previous estimates | MMcf	381	(11,854)	(9,852)
Extensions, discoveries and other additions | MMcf	64,704	1,485	45,645
Purchase of producing properties | MMcf	473
Sale of reserves in place | MMcf	(1,033)	(24,834)	(186,972)
Production | MMcf	(19,611)	(16,617)	(25,502)
Proved reserves ending balance | MMcf	125,438	80,524	132,344
Proved developed reserves | MMcf	57,409	47,349	78,533
Proved undeveloped reserve | MMcf	68,029	33,175	53,811
Oil and Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	115,481	178,004	397,148
Revisions of previous estimates	(5,040)	(14,748)	(14,698)
Extensions, discoveries and other additions	73,931	1,485	62,702
Purchase of producing properties	761
Sale of reserves in place	(1,573)	(25,759)	(232,988)
Production	(27,613)	(23,501)	(34,160)
Proved reserves, ending balance	155,947	115,481	178,004
Proved undeveloped reserve	76,441	67,694	103,615
Proved developed reserves	79,506	47,787	74,389

Supplementary Information on 72

Supplementary Information on Oil and Gas Operations—Unaudited - Average Price and Text (Details) Mcfe in Thousands, MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2017McfeWells$ / mcf$ / Mcfe$ / bblMBblsMMcf	Dec. 31, 2016McfeWells$ / mcf$ / Mcfe$ / bblMBblsMMcf	Dec. 31, 2015McfeWells$ / mcf$ / Mcfe$ / bblMBblsMMcf
Reserve Quantities [Line Items]
Company drilling success rate	100.00%	100.00%	95.00%
Gross wells drilled | Wells	8	5	56
Oklahoma
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)		17,173,000
Texas
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)		44,452,000
Oil
Reserve Quantities [Line Items]
Number of Bcfe additions | MBbls	777	0	163
Consolidated oil and gas production costs per unit of production | $ / bbl	52.49	40.85	50.29
Mcfe of natural gas liquids
Reserve Quantities [Line Items]
Extensions, discoveries and other additions of Bcfe	4,565	0	16,078
Consolidated oil and gas production costs per unit of production | $ / Mcfe	3.23	2.40	2.24
Oil and Natural Gas Reserves
Reserve Quantities [Line Items]
Increase in proved developed and undeveloped reserves	35.00%	(35.12449%)	(55.17909%)
Extensions, discoveries and other additions of Bcfe	73,931	1,485	62,702
Natural Gas
Reserve Quantities [Line Items]
Number of Bcfe additions | MMcf	64,704	1,485	45,645
Consolidated oil and gas production costs per unit of production | $ / mcf	3.03	1.82	2.41

Supplementary Information on 73

Supplementary Information on Oil and Gas Operations—Unaudited - Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows [Abstract]
Future cash flows	$ 539,244	$ 299,035	$ 487,834
Future production costs	(184,171)	(117,283)	(171,678)
Future development costs	(128,447)	(83,720)	(116,591)
Future income taxes	0	0	0
Future net cash flows	226,626	98,032	199,565
10% annual discount	(99,329)	(30,763)	(71,880)
Standardized measure of discounted future net cash flows	$ 127,297	$ 67,269	$ 127,685	$ 548,562

Supplementary Information on 74

Supplementary Information on Oil and Gas Operations—Unaudited - Changes in Standardized Measure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure at beginning of year	$ 67,269	$ 127,685	$ 548,562
Sales and transfers of oil and gas produced, net of production costs	(70,362)	(35,993)	(55,849)
Changes in price, net of future production costs	53,516	(30,427)	(267,710)
Extensions and discoveries, net of future production and development costs	50,977	864	70,928
Changes in estimated future development costs, net of development costs incurred during this period	17,144	26,356	31,007
Revisions of quantity estimates	(7,482)	(14,889)	(14,427)
Accretion of discount	6,727	12,769	60,071
Net change in income taxes	0	0	52,149
Purchase of reserves in place	549	0	0
Sale of reserves in place	(1,305)	(16,701)	(194,454)
Changes in production rates (timing) and other	10,264	(2,395)	(102,592)
Net increase (decrease) in standardized measure	60,028	(60,416)	(420,877)
Standardized measure at end of year	$ 127,297	$ 67,269	$ 127,685

Summarized Quarterly Financia75

Summarized Quarterly Financial Information - Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 35,080	$ 28,184	$ 24,251	$ 20,772	$ 16,429	$ 17,094	$ 15,824	$ 17,320
Loss from operations	221	(1,885)	(2,289)	(3,633)	(8,374)	(22,039)	(22,383)	(37,557)	$ (7,586)	$ (90,353)	$ (292,164)
Loss available to common stockholders	$ (389)	$ (3,085)	$ (3,385)	$ (4,918)	$ (9,659)	$ (23,306)	$ (24,143)	$ (39,137)	$ (11,776)	$ (96,245)	$ (299,929)
Loss per share, Basic (in usd per share)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (0.55)	$ (5.24)	$ (18.45)
Loss per share, Diluted (in usd per share)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (0.55)	$ (5.24)	$ (18.45)
Ceiling test write-downs						$ 8,700	$ 12,800	$ 18,900
Gain on sale of assets									$ 0	$ 0	$ 21,937