TDC Energy S-4 17 Apr 17 Registration of securities issued in business combination transactions Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	872,248
Document Type	S4
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 28,312	$ 148,013
Revenue receivable	10,294	6,476
Joint interest billing receivable	7,632	49,374
Derivative asset	0	1,508
Other current assets	2,353	3,874
Total current assets	48,591	209,245
Oil and gas properties:
Oil and gas properties, full cost method	1,323,333	1,310,891
Unevaluated oil and gas properties	9,015	12,516
Accumulated depreciation, depletion and amortization	(1,243,286)	(1,157,455)
Oil and gas properties, net	89,062	165,952
Other property and equipment	10,951	11,229
Accumulated depreciation of other property and equipment	(10,109)	(8,737)
Total property and equipment	89,904	168,444
Other assets, net of accumulated amortization of $4,385 and $3,842, respectively	6,365	1,630
Total assets	144,860	379,319
Current liabilities:
Accounts payable to vendors	25,265	97,999
Advances from co-owners	2,330	16,118
Oil and gas revenue payable	22,146	18,911
Accrued interest and preferred stock dividend	2,047	12,795
Asset retirement obligation	4,160	6,015
Derivative liability	3,947	0
10% Senior Unsecured Notes due 2017	22,568	0
Other accrued liabilities	3,938	6,946
Total current liabilities	86,401	158,784
Multi-draw Term Loan	7,249	0
Asset retirement obligation	32,450	36,541
Other long-term liabilities	6,027	53
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 21,197 and 16,410 shares, respectively	21	16
Paid-in capital	304,341	290,432
Accumulated other comprehensive income (loss)	(4,750)	947
Accumulated deficit	(550,708)	(454,463)
Total stockholders’ equity	(251,095)	(163,067)
Total liabilities and stockholders’ equity	144,860	379,319
10% Senior Unsecured Notes Due 2017 | Senior Notes
Current liabilities:
10% Senior Unsecured Notes due 2017	0	347,008
10% Senior Secured Notes due 2021 | Senior Notes
Current liabilities:
10% Senior Secured Notes	15,228	0
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Current liabilities:
10% Senior Secured Notes	$ 248,600	$ 0

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Accumulated depreciation and amortization	$ 4,385	$ 3,448
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	21,197,000	16,410,000
Common stock, shares outstanding	21,197,000	16,410,000
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil and gas sales	$ 66,667	$ 115,969	$ 225,021
Expenses:
Lease operating expenses	28,508	40,130	48,597
Production taxes	354	2,470	5,927
Depreciation, depletion and amortization	28,720	63,497	87,818
Ceiling test write-down	40,304	266,562	0
General and administrative	26,040	20,777	22,870
Accretion of asset retirement obligation	2,515	3,259	2,958
Interest expense	30,019	33,766	29,281
Total expenses	156,460	430,461	197,451
Other income (expense):
Gain on sale of assets	0	21,937	0
Other income (expense)	(560)	391	679
Other income (expense), net	(560)	22,328	679
Income (loss) from operations	(90,353)	(292,164)	28,249
Income tax expense (benefit)	543	2,626	(2,941)
Net income (loss)	(90,896)	(294,790)	31,190
Preferred stock dividend	5,349	5,139	5,139
Net income (loss) available to common stockholders	$ (96,245)	$ (299,929)	$ 26,051
Basic
Net income (loss) per share (in usd per share)	$ (5.24)	$ (18.45)	$ 1.57
Diluted
Net income (loss) per share (in usd per share)	$ (5.24)	$ (18.45)	$ 1.57
Weighted average number of common shares:
Basic (shares)	18,354	16,256	16,051
Diluted (shares)	18,354	16,256	16,056

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (90,896)	$ (294,790)	$ 31,190
Change in fair value of derivatives, net of income tax (expense) benefit of $561, $2,650 and ($3,211) respectively	(5,697)	(4,473)	6,516
Comprehensive income (loss)	$ (96,593)	$ (299,263)	$ 37,706

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Income tax (expense) benefit related to other comprehensive income due to derivatives	$ 561	$ 2,650	$ (3,211)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows provided by (used in) operating activities:
Net income (loss)	$ (90,896)	$ (294,790)	$ 31,190
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Deferred tax expense (benefit)	543	2,626	(2,941)
Depreciation, depletion and amortization	28,720	63,497	87,818
Ceiling test write-down	40,304	266,562	0
Accretion of asset retirement obligation	2,515	3,259	2,958
Share based compensation expense	1,444	4,617	5,248
Gain on sale of assets	0	(21,937)	0
Amortization costs and other	2,106	2,259	2,188
Non-cash PIK interest	5,722	0	0
Payments to settle asset retirement obligations	(3,169)	(2,776)	(3,623)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	10,139	0	0
Changes in working capital accounts:
Revenue receivable	(3,818)	10,009	10,083
Joint interest billing receivable	41,400	223	(20,276)
Accounts payable and accrued liabilities	(72,760)	(9,400)	50,243
Advances from co-owners	(13,788)	3,299	11,850
Other	(5,060)	2,657	3,470
Net cash provided by (used in) operating activities	(56,598)	30,105	178,208
Cash flows provided by (used in) investing activities:
Investment in oil and gas properties	(30,366)	(90,218)	(174,633)
Investment in other property and equipment	(24)	(454)	(926)
Sale of oil and gas properties	25,482	271,769	11,908
Net cash provided by (used in) investing activities	(4,908)	181,097	(163,651)
Cash flows used in financing activities:
Net payments for share based compensation	11	(199)	(75)
Deferred financing costs	(3,156)	(1,094)	(253)
Payment of preferred stock dividend	(1,285)	(5,139)	(5,139)
Proceeds from borrowings	10,000	70,000	17,500
Repayment of borrowings	0	(145,000)	(17,500)
Redemption of 2017 Notes	(53,626)	0	0
Costs incurred to issue 2021 Notes and 2021 PIK Notes	(10,139)	0	0
Net cash used in financing activities	(58,195)	(81,432)	(5,467)
Net increase (decrease) in cash and cash equivalents	(119,701)	129,770	9,090
Cash and cash equivalents, beginning of period	148,013	18,243	9,153
Cash and cash equivalents, end of period	28,312	148,013	18,243
Cash paid during the period for:
Interest	33,206	36,217	37,174
Income taxes	$ (18)	$ 0	$ 270

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Preferred Stock	Paid-In Capital	Other Comprehensive Income (Loss)	Accumulated Deficit
Beginning balance at Dec. 31, 2013	$ 99,095	$ 16	$ 1	$ 280,759	$ (1,096)	$ (180,585)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Options exercised	1,032			1,032
Retirement of shares upon vesting of restricted stock	(1,309)	0		(1,309)
Share-based compensation expense	5,248			5,248
Issuance of shares under employee stock purchase plan	276			276
Derivative fair value adjustment, net of tax	6,516				6,516
Preferred stock dividend	(5,139)					(5,139)
Net income (loss)	31,190					31,190
Ending 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 income (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 (in shares)		5
Issuance of shares in debt exchange	12,525			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 income (loss)	(90,896)					(90,896)
Ending balance at Dec. 31, 2016	$ (251,095)	$ 21	$ 1	$ 304,341	$ (4,750)	$ (550,708)

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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 the Gulf Coast Basin. 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. Certain prior period amounts have been reclassified to conform to current year presentation. 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 eight years. Other Assets Other assets at December 31, 2016 included $6.2 million related to cash collateral paid with respect to the Company's surety bonds which secure its offshore decommissioning obligations. Other assets at December 31, 2015 included $1.4 million related to deferred financing costs with respect to the Company's bank credit facility, which were written off upon termination of the bank credit facility. 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. 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, 2016 2015 2014 Shell Trading Co 23% 18% 30% Laclede Energy Resources 17% 21% 24% Superior Natural Gas 14% (a) (a) BG Group 10% 10% (a) Unimark, LLC (a) 17% 14% (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 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, 2016 , 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. We expect to apply the modified retrospective approach upon adoption of this standard. The Company is currently evaluating the effect that this new standard will have on its consolidated financial statements and related disclosures, however, the Company does not expect the adoption of the standard will have a material impact on its consolidated financial statements. In August 2014, the FASB issued ASU 2014-15, " Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)." The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it concludes its plans alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 became effective for us on December 15, 2016. The standard did not impact the Company's disclosures, financial position, results of operations or cash flows. In November 2015, the FASB issued ASU 2015-17, " Balance Sheet Classification of Deferred Taxes " to simplify the presentation of deferred income taxes. The guidance allows for the presentation of all deferred tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent on the balance sheet. We early adopted ASU 2015-17, on a retrospective basis, which had no effect on our financial position, results of operations or cash flows. 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 our 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. ASU 2016-09 is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
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. In connection with the sale, the Company entered into a Contract Operating Services Agreement ("COSA") whereby the Company retained a minimal working interest in the assets sold and agreed to provide certain services as a contract operator for the period of one year from the closing date of the sale. The COSA was terminated on November 1, 2016 and the remaining working interest was transferred to the acquiring owner. 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.

Equity

Equity	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Equity	Equity Common Stock On May 18, 2016, the Company effected a reverse split of the Company's 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. 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 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. Under the terms of the Series B Preferred Stock, any unpaid dividends will accumulate. As of December 31, 2016 , the Company has deferred three quarterly dividends and has accrued a $5.1 million payable related to the three deferred quarterly dividends and the quarterly dividend that was payable on January 15, 2017, which is included in other long-term liabilities on the Consolidated Balance Sheet. If the Company fails to pay six quarterly dividends on the Series B Preferred Stock, whether or not consecutive, holders of the Series B Preferred Stock, voting as a single class, will have the right to elect two additional directors to the Company's Board of Directors until all accumulated and unpaid dividends on the Series B Preferred Stock are paid in full. The Multidraw Term Loan Agreement (see Note 9) currently restricts the Company from paying cash dividends on the Series B Preferred Stock. 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, 2016
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, 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 ) For the Year Ended December 31, 2014 Income(Numerator) Shares Per Net income available to common stockholders $ 26,051 16,051 Attributable to participating securities (855 ) — BASIC EPS $ 25,196 16,051 $ 1.57 Net income available to common stockholders $ 26,051 16,051 Effect of dilutive securities: Stock options — 5 Attributable to participating securities (854 ) — DILUTED EPS $ 25,197 16,056 $ 1.57 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 for 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. Common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 1.3 million shares during the year ended December 31, 2014 were not included in the computation of diluted earnings per share because the inclusion would have been anti-dilutive. Options to purchase 0.3 million shares of common stock were outstanding during the year ended December 31, 2014 and were not included in the computation of diluted earnings per share because the options' exercise prices were in excess of the average market price of the common shares.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 is as follows (in thousands): Year Ended December 31, 2016 2015 2014 Stock options: Incentive Stock Options (share settled) $ 206 $ 243 $ 573 Non-Qualified Stock Options (share settled) 164 71 171 Restricted stock (share settled) 1,073 4,303 4,504 Cash settled stock units 244 (439 ) 3,094 Share-based compensation $ 1,687 $ 4,178 $ 8,342 During the years ended December 31, 2016 and 2014 , the Company capitalized $0.1 million , and $1.5 million , respectively, 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, 2016 , 2015 and 2014 , the Company recorded income tax benefits of approximately $0.5 million , $1.5 million and $2.3 million , respectively, related to share-based compensation expense recognized during those periods. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred and the Company has net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for any periods presented. Share-Based compensation settled in shares At December 31, 2016 , the Company had $1.8 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 equally 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 100% of 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 a stock option forfeiture rate and 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 2016 and 2014 : Years Ended December 31, 2016 2014 Dividend yield —% —% Expected volatility 62.0%-79.99% 79.4% - 80.0% Risk-free rate 1.255%-2.09% 1.81% - 2.015% Expected term 6 years 6 years Forfeiture rate 5.0% 5.0% Stock options granted (1) 1,168,754 17,359 Wgtd. avg. grant date fair value per share $1.96 $11.36 Fair value of grants (1) $2,293,000 $197,000 (1) Prior to applying estimated forfeiture rate The following table details stock option activity during the year ended December 31, 2016 : Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Remaining Life Aggregate Intrinsic Value (000’s) Outstanding at beginning of year 340,492 $ 24.38 Granted 1,168,754 3.33 Expired/cancelled/forfeited (96,306 ) 22.01 Exercised — — Outstanding at end of year 1,412,940 7.13 8.74 $ 186 Options exercisable at end of year 256,013 $ 24.11 4.73 $ — Options expected to vest 1,355,094 7.29 8.71 $ 176 The total fair value of stock options that vested during the years ended December 31, 2016 , 2015 and 2014 was $0.4 million , $0.8 million and $1.0 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, 2016 : Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg. Exercise Outstanding Remaining Exercise Exercisable Exercise Price 12/31/2016 Contractual Life Price 12/31/2016 Price $0.00-$2.49 66,373 9.20 $2.37 — $2.50-$3.49 878,833 9.74 $3.17 — $3.50-$4.99 206,769 9.38 $4.26 — $15.00-$30.32 260,965 4.77 $23.94 256,013 $24.11 1,412,940 8.74 $7.13 256,013 $24.11 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, and compensation expense is recognized assuming a 5% estimated forfeiture rate. Restricted stock granted to employees generally vests evenly 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, 2016 : Number of Shares Wgtd. Avg. Fair Value per Share Outstanding at beginning of year 296,259 $ 16.32 Granted — — Cancelled/forfeited (67,672 ) 16.97 Lapse of restrictions (150,030 ) 15.90 Outstanding at December 31, 2016 78,557 $ 16.57 The weighted average grant date fair value of restricted stock granted during the years ended December 31, 2015 and 2014 was $5.08 and $17.28 , 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, 2016 , 2015 and 2014 was $2.4 million , $4.7 million and $5.0 million , respectively. At December 31, 2016 , the weighted average remaining life of restricted stock outstanding was approximately one year . Share-Based compensation settled in cash Restricted Stock Units The Company may grant restricted stock units ("RSUs") to employees that vest evenly 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 2016 , the Company paid $0.3 million for 0.1 million RSUs 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 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. 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 Company's and its peer group's stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. As of December 31, 2016 , the Company had a liability for RSUs and MRSUs outstanding in the amount of $0.1 million based upon the closing stock price at December 31, 2016 . The following table details MRSU and RSU activity during the year ended December 31, 2016 : MRSU RSU Total Outstanding at beginning of year 25,821 188,337 214,158 Granted — — — Expired/Cancelled/Forfeited (2,285 ) (44,897 ) (47,182 ) Vested/Paid (8,607 ) (111,461 ) (120,068 ) Outstanding at December 31, 2016 14,929 31,979 46,908

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2016
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 describes the changes to the Company’s asset retirement obligation (in thousands): Year Ended December 31, 2016 2015 Asset retirement obligation, beginning of period $ 42,556 $ 54,970 Liabilities incurred — 466 Liabilities settled (3,296 ) (2,776 ) Accretion expense 2,515 3,259 Revisions in estimated cash flows (1,746 ) (11,137 ) Divestiture of oil and gas properties (3,419 ) (2,226 ) Asset retirement obligation, end of period 36,610 42,556 Less: current portion of asset retirement obligation (4,160 ) (6,015 ) Long-term asset retirement obligation $ 32,450 $ 36,541 Divestitures of oil and gas properties during 2016 included $3.3 million as a result of the sale of our remaining Oklahoma assets. Divestitures of oil and gas properties during 2015 included $1.8 million as a result of the sale of our Woodford Shale and Mississippian Lime assets. The liabilities incurred, revisions in estimated cash flows and divestitures represent non-cash investing activities for purposes of the statement of cash flows.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 , all of the Company's outstanding derivative instruments were designated as cash flow hedges. Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $1.8 million , $15.9 million and ($4.2) million , Ngl hedges of $0 , $0.5 million and $0.3 million , and oil hedges of $0 , $0.6 million and $0.9 million , for the years ended December 31, 2016 , 2015 and 2014 , respectively. As of December 31, 2016 , the Company had entered into the following gas hedge contracts: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: January 2017 - December 2017 Swap 10,000 Mmbtu $3.26 January 2017 - March 2018 Swap 10,000 Mmbtu $3.01 April 2017 - March 2018 Swap 10,000 Mmbtu $3.40 At December 31, 2016 , the Company had recognized a liability of approximately $4.8 million related to the estimated fair value of these derivative contracts. Based on estimated future commodity prices as of December 31, 2016 , the Company would realize a $2.5 million loss , net of taxes, during the next 12 months. This loss is expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts. During March 2017, we entered into the following additional hedge contract accounted for as a cash flow hedge: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: October 2017 - March 2018 Swap 10,000 Mmbtu $3.22 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, 2016 and December 31, 2015 : Commodity Derivatives Period Balance Sheet Fair Value December 31, 2016 Derivative liability $ (3,947 ) December 31, 2016 Other long-term liabilities $ (803 ) December 31, 2015 Derivative asset $ 1,508 Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2016 , 2015 and 2014 : Instrument Amount of Gain (Loss) Location of Amount of Gain (Loss) Reclassified into 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 Commodity Derivatives at December 31, 2014 $ 6,683 Oil and gas sales $ (3,044 )

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 were in the form of swaps based on NYMEX pricing for 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, 2016 and December 31, 2015 (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, 2016 $ — $ (4,750 ) $ — At December 31, 2015 $ — $ 1,508 $ — The fair value of the Company's cash and cash equivalents approximated book value at December 31, 2016 and 2015 . The fair value of the Multidraw Term Loan Agreement approximated face value as of December 31, 2016 . The fair value of the Company's bank credit facility, which was terminated in October 2016, approximated book value as of December 31, 2015 . 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, 2016 and 2015 , respectively (in thousands). Fair Value at 12/31/16 Face Value at 12/31/16 Carrying value at 12/31/16 Fair Value at 12/31/15 Face Value at 12/31/15 Carrying value at 12/31/15 2017 Notes $ 21,970 $ 22,650 $ 22,568 $ 238,000 $ 350,000 $ 347,008 2021 Notes 12,192 14,177 15,228 — — — 2021 PIK Notes 177,732 243,468 248,600 — — — $ 211,894 $ 280,295 $ 286,396 $ 238,000 $ 350,000 $ 347,008

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
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 its 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 its 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 is $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. Unless the Company exercises its payable in kind ("PIK") interest option, 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 may, at its option, for one or more of the first three interest payment dates of the 2021 PIK Notes, 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. We exercised this PIK option in connection with the interest payment due on February 15, 2017. As of December 31, 2016 , 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, 2016 , the Company was in compliance with all of the covenants under the 2021 Notes. The 2017 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on March 1 and September 1 of each year and the 2017 Notes mature on September 1, 2017. As of December 31, 2016 , the Company was in compliance with the remaining covenants under the 2017 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. 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, 2016 , $1.2 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $1.5 million of amortization expense as a reduction to interest expense during the year ended December 31, 2016 . 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 (including the remaining 2017 Notes), 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, 2016 , the Company has $10.0 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 (a) 1.7 to 1.0 as measured on December 31, 2016 and March 31, 2017, and (b) 2.0 to 1.0 as measured on June 30, 2017, and the last day of each calendar quarter thereafter (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, 2016 , 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 and $3.0 million of related unamortized financing costs at December 31, 2016 and 2015 , respectively. The 2021 Notes are reflected net of $0.1 million of related unamortized financing costs as of December 31, 2016 and the Term Loans are reflected net of $2.8 million of related unamortized financing costs as of December 31, 2016 . 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, 2016 and 2015 (in thousands):. December 31, 2016 December 31, 2015 2017 Notes 2021 Notes 2021 PIK Notes Term Loans 2017 Notes 2021 Notes 2021 PIK Notes Term Loans Face Value $ 22,650 $ 14,177 $ 243,468 $ 10,000 $ 350,000 $ — $ — $ — Unamortized Deferred Financing Costs (82 ) (108 ) — (2,751 ) (2,992 ) — — — Excess (shortfall) Carrying Value — 1,159 (590 ) — — — — — Accrued PIK Interest — — 5,722 — — — — — Carrying Value $ 22,568 $ 15,228 $ 248,600 $ 7,249 $ 347,008 $ — $ — $ — On March 1, 2017, we notified the holders of the 2017 Notes that we will redeem the remaining $22.7 million of 2017 Notes on March 31, 2017 at a redemption price of 100% of the principal amount thereof, plus accrued interest to the redemption date. We expect to pay the redemption price with a combination of cash on hand and amounts borrowed under the Multidraw Term Loan Agreement described above.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
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 and E. Wayne Nordberg and William W. Rucks, IV, two of the Company’s directors, are working 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 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, and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $200 . 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, and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $300 . During 2014 , in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson and Green, or their affiliates, in the amounts of $80,000 and $116,000 , respectively, and with respect to Mr. Nordberg, costs billed equaled revenues disbursed. No such disbursements were made to Mr. Rucks during any reported period. 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, 2016 , the Company’s joint interest billing receivable included approximately $8,000 from the related parties discussed above or their affiliates, attributable to their share of costs. This represents less than 1% of the Company’s total joint interest billing receivable at December 31, 2016 . Periodically, the Company charters private aircraft for business purposes. During 2014 , the Company paid approximately $18,000 to a third party operator in connection with the Company’s use of flight hours owned by Charles T. Goodson through a fractional ownership arrangement with the third party operator. These amounts represent the cost of the hours purchased by Mr. Goodson. No such amounts were incurred during 2016 and 2015. The Company’s use of flight hours purchased by Mr. Goodson was pre-approved by the Company’s Audit Committee and there is no agreement or obligation by or on behalf of the Company to utilize this aircraft arrangement.

Ceiling Test Write-down

Ceiling Test Write-down	12 Months Ended
	Dec. 31, 2016
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 2016 and 2015 . The Company did not recognize a ceiling test write-down in the fourth quarter of 2016 . The Company’s cash flow hedges in place at December 31, 2015 decreased the ceiling test write-down by approximately $1.1 million . The Company did not recognize a ceiling test write-down during 2014 .

Other Comprehensive Income (Los

Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2016
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 )

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company typically provides for income taxes at a statutory rate of 35% 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 $177.4 million as of December 31, 2016 . An analysis of the Company’s deferred tax assets and liabilities follows (amounts in thousands): December 31, 2016 2015 Net operating loss carryforwards $ 92,072 $ 51,519 Percentage depletion carryforward 9,372 10,592 Alternative minimum tax credits 784 784 Contributions carryforward and other 282 266 Temporary differences: Oil and gas properties 27,992 62,786 Asset retirement obligation 13,620 15,831 Derivatives 1,767 (561 ) Share-based compensation 1,870 2,291 Original issue discount on debt exchanges 29,646 — Valuation allowance (177,405 ) (143,508 ) Deferred tax asset (liability) $ — $ — At December 31, 2016 , the Company had approximately $260.1 million of operating loss carryforwards, of which $12.6 million relates to excess tax benefits with respect to share-based compensation that have not been recognized in the financial statements. If not utilized, approximately $6.9 million of such carryforwards would expire in 2025 and the remainder would expire by the year 2036 . The Company has available for tax reporting purposes $26.8 million in statutory depletion deductions that may be carried forward indefinitely. Income tax expense (benefit) for each of the years ended December 31, 2016 , 2015 and 2014 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, 2016 2015 2014 Amount computed using the statutory rate $ (31,623 ) $ (102,257 ) $ 9,887 Increase (reduction) in taxes resulting from: State & local taxes (2,000 ) (6,477 ) 904 Percentage depletion carryforward (163 ) (404 ) (1,564 ) Non-deductible stock option expense (1) 77 90 213 Share-based compensation (2) 707 1,317 90 Other 1,415 113 (643 ) Change in valuation allowance 32,130 110,244 (11,828 ) Income tax expense (benefit) $ 543 $ 2,626 $ (2,941 ) (1) Relates to compensation expense recognized on the vesting of 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, 2016
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, 2016 under these operating leases are as follows (in thousands): 2017 $ 1,208 2018 470 2019 447 2020 445 2021 434 Thereafter 811 $ 3,815 Total rent expense under operating leases was approximately $1.5 million , $1.7 million and $1.6 million in 2016 , 2015 and 2014 , respectively.

Supplementary Information on Oi

Supplementary Information on Oil and Gas Operations-Unaudited	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Acquisition costs: Proved $ 3,346 $ 2,287 $ 3,064 Unproved (1) 2,197 2,550 39,164 Divestiture of proved leasehold (7,000 ) — — Exploration costs: Proved 715 29,322 67,297 Unproved 603 7,677 13,515 Development costs 1,522 9,888 55,722 Capitalized general and administrative and interest costs 7,558 12,881 22,121 Total costs incurred $ 8,941 $ 64,605 $ 200,883 For the Year-Ended December 31, 2016 2015 2014 Accumulated depreciation, depletion and amortization (DD&A) Balance, beginning of year $ (1,157,455 ) $ (1,648,060 ) $ (1,553,044 ) Provision for DD&A (27,962 ) (62,138 ) (86,406 ) Ceiling test writedown (40,304 ) (266,562 ) — Sale of proved properties and other (2) (3) (17,565 ) 819,305 (8,610 ) Balance, end of year $ (1,243,286 ) $ (1,157,455 ) $ (1,648,060 ) DD&A per Mcfe $ 1.19 $ 1.82 $ 1.99 (1) During 2014 , the Company entered into a joint venture in Louisiana for an aggregate purchase price of $24 million for an approximate 30,000 acre leasehold position. (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 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 . During 2014 , the Company sold its Eagle Ford assets for net proceeds of approximately $9.8 million . At December 31, 2016 and 2015 , unevaluated oil and gas properties totaled $9.0 million and $12.5 million , respectively, and were not subject to depletion. Unevaluated costs at December 31, 2016 included $0.4 million of costs related to one development well in progress at year-end. These costs are expected to be transferred to evaluated oil and gas properties during 2017 upon the completion of drilling. At December 31, 2015 , unevaluated costs included $0.2 million related to 2 exploratory wells in progress. All of these costs were transferred to evaluated oil and gas properties during 2016 . The Company capitalized $0.9 million , $4.7 million and $10.0 million of interest during 2016 , 2015 and 2014 , respectively. Of the total unevaluated oil and gas property costs of $9.0 million at December 31, 2016 , $3.4 million , or 38% , was incurred in 2016 , $1.1 million , or 12% , was incurred in 2015 and $4.5 million , or 50% , was incurred in prior years. The Company expects that the majority of the unevaluated costs at December 31, 2016 will be evaluated within the next three years, including $1.8 million that the Company expects to be evaluated during 2017 . Oil and Gas Reserve Information The Company’s net proved oil and gas reserves at December 31, 2016 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, 2013 3,031 28,430 250,109 296,723 Revisions of previous estimates (37 ) 2,894 9,976 12,650 Extensions, discoveries and other additions 475 49,990 82,364 135,205 Sale of reserves in place (229 ) (334 ) (2,396 ) (4,105 ) Production (803 ) (7,482 ) (31,028 ) (43,325 ) 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 Proved developed reserves As of December 31, 2014 2,089 42,584 182,567 237,688 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 Proved undeveloped reserves As of December 31, 2014 348 30,914 126,458 159,460 As of December 31, 2015 257 19,034 53,811 74,389 As of December 31, 2016 185 13,502 33,175 47,787 Year Ended December 31, 2016 During 2016 , the Company’s estimated proved reserves decrease d by 35% . The decline in reserves was 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 five 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. Year Ended December 31, 2014 During 2014, the Company's estimated proved reserves increase d by 34% . Extensions, discoveries and other additions of 135 Bcfe were primarily due to successful drilling programs in the Company's Oklahoma and East Texas fields and its Thunder Bayou discovery. The Company added approximately 72 Bcfe of proved reserves in Oklahoma, 46 Bcfe in Texas and 15 Bcfe in the Gulf Coast. Overall, the Company had a 91% drilling success rate during 2014 on 58 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, 2016 2015 2014 Future cash flows $ 299,035 $ 487,834 $ 1,711,404 Future production costs (117,283 ) (171,678 ) (372,690 ) Future development costs (83,720 ) (116,591 ) (244,784 ) Future income taxes — — (121,192 ) Future net cash flows 98,032 199,565 972,738 10% annual discount (30,763 ) (71,880 ) (424,176 ) Standardized measure of discounted future net cash flows $ 67,269 $ 127,685 $ 548,562 Changes in Standardized Measure Year Ended December 31, 2016 2015 2014 Standardized measure at beginning of year $ 127,685 $ 548,562 $ 451,180 Sales and transfers of oil and gas produced, net of production costs (35,993 ) (55,849 ) (173,540 ) Changes in price, net of future production costs (30,427 ) (267,710 ) 37,204 Extensions and discoveries, net of future production and development costs 864 70,928 237,290 Changes in estimated future development costs, net of development costs incurred during this period 26,356 31,007 11,094 Revisions of quantity estimates (14,889 ) (14,427 ) 25,591 Accretion of discount 12,769 60,071 47,130 Net change in income taxes — 52,149 (32,034 ) Sale of reserves in place (16,701 ) (194,454 ) (7,240 ) Changes in production rates (timing) and other (2,395 ) (102,592 ) (48,113 ) Net increase (decrease) in standardized measure (60,416 ) (420,877 ) 97,382 Standardized measure at end of year $ 67,269 $ 127,685 $ 548,562 The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were: 2016 2015 2014 Oil, $/Bbl $40.85 $50.29 $96.45 Ngls, $/Mcfe 2.40 2.24 4.11 Natural Gas, $/Mcf 1.82 2.41 3.80

Summarized Quarterly Financial

Summarized Quarterly Financial Information-Unaudited	12 Months Ended
	Dec. 31, 2016
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 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 ) Earnings per share: Basic $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) Diluted $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) 2015: Revenues $ 33,451 $ 32,550 $ 26,872 $ 23,096 Loss from operations (2) (121,887 ) (57,796 ) (50,617 ) (61,864 ) Loss available to common stockholders (2) (122,240 ) (61,083 ) (51,910 ) (64,696 ) Earnings per share: Basic $ (7.55 ) $ (3.77 ) $ (3.19 ) $ (3.94 ) Diluted $ (7.55 ) $ (3.77 ) $ (3.19 ) $ (3.94 ) (1) Loss from operations and loss available to common stockholders reported during the three months ended March 31, June 30 and September 30, 2016 included pretax ceiling test write-downs of $18.9 million , $12.8 million and $8.7 million , respectively. (2) Loss from operations and loss available to common stockholders reported during the three months ended March 31, June 30, September 30 and December 31, 2015 included pretax ceiling test write-downs of $108.9 million , $65.5 million , $40.2 million and $51.9 million , respectively. Additionally, loss from operations and loss available to common stockholders reported during the three months ended June 30, 2015 included a pretax gain on sale of oil and gas properties of $21.5 million .

Organization and Summary of S25

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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. Certain prior period amounts have been reclassified to conform to current year presentation.
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 eight years.
Other Assets	Other Assets Other assets at December 31, 2016 included $6.2 million related to cash collateral paid with respect to the Company's surety bonds which secure its offshore decommissioning obligations. Other assets at December 31, 2015 included $1.4 million related to deferred financing costs with respect to the Company's bank credit facility, which were written off upon termination of the bank credit facility.
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 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, 2016 , 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. We expect to apply the modified retrospective approach upon adoption of this standard. The Company is currently evaluating the effect that this new standard will have on its consolidated financial statements and related disclosures, however, the Company does not expect the adoption of the standard will have a material impact on its consolidated financial statements. In August 2014, the FASB issued ASU 2014-15, " Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)." The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it concludes its plans alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 became effective for us on December 15, 2016. The standard did not impact the Company's disclosures, financial position, results of operations or cash flows. In November 2015, the FASB issued ASU 2015-17, " Balance Sheet Classification of Deferred Taxes " to simplify the presentation of deferred income taxes. The guidance allows for the presentation of all deferred tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent on the balance sheet. We early adopted ASU 2015-17, on a retrospective basis, which had no effect on our financial position, results of operations or cash flows. 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 our 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. ASU 2016-09 is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.

Organization and Summary of S26

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Shell Trading Co 23% 18% 30% Laclede Energy Resources 17% 21% 24% Superior Natural Gas 14% (a) (a) BG Group 10% 10% (a) Unimark, LLC (a) 17% 14% (a) Less than 10 percent

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
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, 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 ) For the Year Ended December 31, 2014 Income(Numerator) Shares Per Net income available to common stockholders $ 26,051 16,051 Attributable to participating securities (855 ) — BASIC EPS $ 25,196 16,051 $ 1.57 Net income available to common stockholders $ 26,051 16,051 Effect of dilutive securities: Stock options — 5 Attributable to participating securities (854 ) — DILUTED EPS $ 25,197 16,056 $ 1.57

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 is as follows (in thousands): Year Ended December 31, 2016 2015 2014 Stock options: Incentive Stock Options (share settled) $ 206 $ 243 $ 573 Non-Qualified Stock Options (share settled) 164 71 171 Restricted stock (share settled) 1,073 4,303 4,504 Cash settled stock units 244 (439 ) 3,094 Share-based compensation $ 1,687 $ 4,178 $ 8,342
Schedule of stock option valuation assumptions	The following table outlines the assumptions used in computing the fair value of stock options granted during 2016 and 2014 : Years Ended December 31, 2016 2014 Dividend yield —% —% Expected volatility 62.0%-79.99% 79.4% - 80.0% Risk-free rate 1.255%-2.09% 1.81% - 2.015% Expected term 6 years 6 years Forfeiture rate 5.0% 5.0% Stock options granted (1) 1,168,754 17,359 Wgtd. avg. grant date fair value per share $1.96 $11.36 Fair value of grants (1) $2,293,000 $197,000 (1) Prior to applying estimated forfeiture rate
Schedule of stock options activity	The following table details stock option activity during the year ended December 31, 2016 : Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Remaining Life Aggregate Intrinsic Value (000’s) Outstanding at beginning of year 340,492 $ 24.38 Granted 1,168,754 3.33 Expired/cancelled/forfeited (96,306 ) 22.01 Exercised — — Outstanding at end of year 1,412,940 7.13 8.74 $ 186 Options exercisable at end of year 256,013 $ 24.11 4.73 $ — Options expected to vest 1,355,094 7.29 8.71 $ 176
Schedule of stock option plans, by exercise price range	The following table summarizes information regarding stock options outstanding at December 31, 2016 : Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg. Exercise Outstanding Remaining Exercise Exercisable Exercise Price 12/31/2016 Contractual Life Price 12/31/2016 Price $0.00-$2.49 66,373 9.20 $2.37 — $2.50-$3.49 878,833 9.74 $3.17 — $3.50-$4.99 206,769 9.38 $4.26 — $15.00-$30.32 260,965 4.77 $23.94 256,013 $24.11 1,412,940 8.74 $7.13 256,013 $24.11
Schedule of restricted stock units activity	The following table details restricted stock activity during the year ended December 31, 2016 : Number of Shares Wgtd. Avg. Fair Value per Share Outstanding at beginning of year 296,259 $ 16.32 Granted — — Cancelled/forfeited (67,672 ) 16.97 Lapse of restrictions (150,030 ) 15.90 Outstanding at December 31, 2016 78,557 $ 16.57 The following table details MRSU and RSU activity during the year ended December 31, 2016 : MRSU RSU Total Outstanding at beginning of year 25,821 188,337 214,158 Granted — — — Expired/Cancelled/Forfeited (2,285 ) (44,897 ) (47,182 ) Vested/Paid (8,607 ) (111,461 ) (120,068 ) Outstanding at December 31, 2016 14,929 31,979 46,908

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Changes to the Company's asset retirement obligation liability	The following table describes the changes to the Company’s asset retirement obligation (in thousands): Year Ended December 31, 2016 2015 Asset retirement obligation, beginning of period $ 42,556 $ 54,970 Liabilities incurred — 466 Liabilities settled (3,296 ) (2,776 ) Accretion expense 2,515 3,259 Revisions in estimated cash flows (1,746 ) (11,137 ) Divestiture of oil and gas properties (3,419 ) (2,226 ) Asset retirement obligation, end of period 36,610 42,556 Less: current portion of asset retirement obligation (4,160 ) (6,015 ) Long-term asset retirement obligation $ 32,450 $ 36,541

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Oil and gas contracts	As of December 31, 2016 , the Company had entered into the following gas hedge contracts: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: January 2017 - December 2017 Swap 10,000 Mmbtu $3.26 January 2017 - March 2018 Swap 10,000 Mmbtu $3.01 April 2017 - March 2018 Swap 10,000 Mmbtu $3.40 At December 31, 2016 , the Company had recognized a liability of approximately $4.8 million related to the estimated fair value of these derivative contracts. Based on estimated future commodity prices as of December 31, 2016 , the Company would realize a $2.5 million loss , net of taxes, during the next 12 months. This loss is expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts. During March 2017, we entered into the following additional hedge contract accounted for as a cash flow hedge: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: October 2017 - March 2018 Swap 10,000 Mmbtu $3.22
Effect of cash flow hedges on the consolidated balance sheet	Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2016 and December 31, 2015 : Commodity Derivatives Period Balance Sheet Fair Value December 31, 2016 Derivative liability $ (3,947 ) December 31, 2016 Other long-term liabilities $ (803 ) December 31, 2015 Derivative asset $ 1,508
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, 2016 , 2015 and 2014 : Instrument Amount of Gain (Loss) Location of Amount of Gain (Loss) Reclassified into 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 Commodity Derivatives at December 31, 2014 $ 6,683 Oil and gas sales $ (3,044 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and December 31, 2015 (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, 2016 $ — $ (4,750 ) $ — At December 31, 2015 $ — $ 1,508 $ —
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, 2016 and 2015 , respectively (in thousands). Fair Value at 12/31/16 Face Value at 12/31/16 Carrying value at 12/31/16 Fair Value at 12/31/15 Face Value at 12/31/15 Carrying value at 12/31/15 2017 Notes $ 21,970 $ 22,650 $ 22,568 $ 238,000 $ 350,000 $ 347,008 2021 Notes 12,192 14,177 15,228 — — — 2021 PIK Notes 177,732 243,468 248,600 — — — $ 211,894 $ 280,295 $ 286,396 $ 238,000 $ 350,000 $ 347,008

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (in thousands):. December 31, 2016 December 31, 2015 2017 Notes 2021 Notes 2021 PIK Notes Term Loans 2017 Notes 2021 Notes 2021 PIK Notes Term Loans Face Value $ 22,650 $ 14,177 $ 243,468 $ 10,000 $ 350,000 $ — $ — $ — Unamortized Deferred Financing Costs (82 ) (108 ) — (2,751 ) (2,992 ) — — — Excess (shortfall) Carrying Value — 1,159 (590 ) — — — — — Accrued PIK Interest — — 5,722 — — — — — Carrying Value $ 22,568 $ 15,228 $ 248,600 $ 7,249 $ 347,008 $ — $ — $ —

Other Comprehensive Income (L33

Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2016
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, 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 )

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Net operating loss carryforwards $ 92,072 $ 51,519 Percentage depletion carryforward 9,372 10,592 Alternative minimum tax credits 784 784 Contributions carryforward and other 282 266 Temporary differences: Oil and gas properties 27,992 62,786 Asset retirement obligation 13,620 15,831 Derivatives 1,767 (561 ) Share-based compensation 1,870 2,291 Original issue discount on debt exchanges 29,646 — Valuation allowance (177,405 ) (143,508 ) Deferred tax asset (liability) $ — $ —
Income Tax Reconciliation	Income tax expense (benefit) for each of the years ended December 31, 2016 , 2015 and 2014 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, 2016 2015 2014 Amount computed using the statutory rate $ (31,623 ) $ (102,257 ) $ 9,887 Increase (reduction) in taxes resulting from: State & local taxes (2,000 ) (6,477 ) 904 Percentage depletion carryforward (163 ) (404 ) (1,564 ) Non-deductible stock option expense (1) 77 90 213 Share-based compensation (2) 707 1,317 90 Other 1,415 113 (643 ) Change in valuation allowance 32,130 110,244 (11,828 ) Income tax expense (benefit) $ 543 $ 2,626 $ (2,941 ) (1) Relates to compensation expense recognized on the vesting of 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, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Lease Commitments	Future minimum lease commitments as of December 31, 2016 under these operating leases are as follows (in thousands): 2017 $ 1,208 2018 470 2019 447 2020 445 2021 434 Thereafter 811 $ 3,815

Supplementary Information on 36

Supplementary Information on Oil and Gas Operations-Unaudited (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Acquisition costs: Proved $ 3,346 $ 2,287 $ 3,064 Unproved (1) 2,197 2,550 39,164 Divestiture of proved leasehold (7,000 ) — — Exploration costs: Proved 715 29,322 67,297 Unproved 603 7,677 13,515 Development costs 1,522 9,888 55,722 Capitalized general and administrative and interest costs 7,558 12,881 22,121 Total costs incurred $ 8,941 $ 64,605 $ 200,883 For the Year-Ended December 31, 2016 2015 2014 Accumulated depreciation, depletion and amortization (DD&A) Balance, beginning of year $ (1,157,455 ) $ (1,648,060 ) $ (1,553,044 ) Provision for DD&A (27,962 ) (62,138 ) (86,406 ) Ceiling test writedown (40,304 ) (266,562 ) — Sale of proved properties and other (2) (3) (17,565 ) 819,305 (8,610 ) Balance, end of year $ (1,243,286 ) $ (1,157,455 ) $ (1,648,060 ) DD&A per Mcfe $ 1.19 $ 1.82 $ 1.99 (1) During 2014 , the Company entered into a joint venture in Louisiana for an aggregate purchase price of $24 million for an approximate 30,000 acre leasehold position. (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 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 . During 2014 , the Company sold its Eagle Ford assets for net proceeds of approximately $9.8 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, 2013 3,031 28,430 250,109 296,723 Revisions of previous estimates (37 ) 2,894 9,976 12,650 Extensions, discoveries and other additions 475 49,990 82,364 135,205 Sale of reserves in place (229 ) (334 ) (2,396 ) (4,105 ) Production (803 ) (7,482 ) (31,028 ) (43,325 ) 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 Proved developed reserves As of December 31, 2014 2,089 42,584 182,567 237,688 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 Proved undeveloped reserves As of December 31, 2014 348 30,914 126,458 159,460 As of December 31, 2015 257 19,034 53,811 74,389 As of December 31, 2016 185 13,502 33,175 47,787
Standardized measure of discounted future cash flows	Standardized Measure December 31, 2016 2015 2014 Future cash flows $ 299,035 $ 487,834 $ 1,711,404 Future production costs (117,283 ) (171,678 ) (372,690 ) Future development costs (83,720 ) (116,591 ) (244,784 ) Future income taxes — — (121,192 ) Future net cash flows 98,032 199,565 972,738 10% annual discount (30,763 ) (71,880 ) (424,176 ) Standardized measure of discounted future net cash flows $ 67,269 $ 127,685 $ 548,562
Schedule of changes in standardized measure of discounted future net cash flows	Changes in Standardized Measure Year Ended December 31, 2016 2015 2014 Standardized measure at beginning of year $ 127,685 $ 548,562 $ 451,180 Sales and transfers of oil and gas produced, net of production costs (35,993 ) (55,849 ) (173,540 ) Changes in price, net of future production costs (30,427 ) (267,710 ) 37,204 Extensions and discoveries, net of future production and development costs 864 70,928 237,290 Changes in estimated future development costs, net of development costs incurred during this period 26,356 31,007 11,094 Revisions of quantity estimates (14,889 ) (14,427 ) 25,591 Accretion of discount 12,769 60,071 47,130 Net change in income taxes — 52,149 (32,034 ) Sale of reserves in place (16,701 ) (194,454 ) (7,240 ) Changes in production rates (timing) and other (2,395 ) (102,592 ) (48,113 ) Net increase (decrease) in standardized measure (60,416 ) (420,877 ) 97,382 Standardized measure at end of year $ 67,269 $ 127,685 $ 548,562
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: 2016 2015 2014 Oil, $/Bbl $40.85 $50.29 $96.45 Ngls, $/Mcfe 2.40 2.24 4.11 Natural Gas, $/Mcf 1.82 2.41 3.80

Summarized Quarterly Financia37

Summarized Quarterly Financial Information-Unaudited (Tables)	12 Months Ended
	Dec. 31, 2016
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 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 ) Earnings per share: Basic $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) Diluted $ (2.09 ) $ (1.38 ) $ (1.31 ) $ (0.46 ) 2015: Revenues $ 33,451 $ 32,550 $ 26,872 $ 23,096 Loss from operations (2) (121,887 ) (57,796 ) (50,617 ) (61,864 ) Loss available to common stockholders (2) (122,240 ) (61,083 ) (51,910 ) (64,696 ) Earnings per share: Basic $ (7.55 ) $ (3.77 ) $ (3.19 ) $ (3.94 ) Diluted $ (7.55 ) $ (3.77 ) $ (3.19 ) $ (3.94 ) (1) Loss from operations and loss available to common stockholders reported during the three months ended March 31, June 30 and September 30, 2016 included pretax ceiling test write-downs of $18.9 million , $12.8 million and $8.7 million , respectively. (2) Loss from operations and loss available to common stockholders reported during the three months ended March 31, June 30, September 30 and December 31, 2015 included pretax ceiling test write-downs of $108.9 million , $65.5 million , $40.2 million and $51.9 million , respectively. Additionally, loss from operations and loss available to common stockholders reported during the three months ended June 30, 2015 included a pretax gain on sale of oil and gas properties of $21.5 million .

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, 2016
Minimum
Property, Plant and Equipment [Line Items]
Useful life (in years)	3 years
Maximum
Property, Plant and Equipment [Line Items]
Useful life (in years)	8 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Shell Trading Co
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	23.00%	18.00%	30.00%
Laclede Energy Resources
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	17.00%	21.00%	24.00%
Superior Natural Gas
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	14.00%
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%	14.00%

Organization and Summary of S40

Organization and Summary of Significant Accounting Policies - Other Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash collateral	$ 6.2
Deferred finance costs		$ 1.4

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) $ in Thousands, Mcfe in Billions	Jun. 04, 2015USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2016USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)Mcfe	Oct. 31, 2016USD ($)	Apr. 20, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of assets				$ 21,500	$ 0	$ 21,937	$ 0
Sale of oil and gas properties					25,482	271,769	$ 11,908
Woodford And Mississippian Lime
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from sale of a majority of interests	$ 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]
Net proceeds from sale of a majority of interests									$ 18,000
Oklahoma Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from sale of a majority of interests								$ 700
Sale of oil and gas properties					$ 17,600
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

Equity - Common Stock (Details)

Equity - Common Stock (Details) shares in Thousands	May 18, 2016shares	Dec. 31, 2016shares	May 17, 2016shares	Dec. 31, 2015shares
Class of Stock [Line Items]
Common stock, shares outstanding		21,197		16,410
Common Stock
Class of Stock [Line Items]
Reverse stock split, conversion ratio	0.25
Common stock, shares outstanding	17,600		70,500

Equity - Convertible Preferred

Equity - Convertible Preferred Stock (Details)	12 Months Ended
	Dec. 31, 2016USD ($)payment$ / sharesRateshares	Dec. 31, 2015shares
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	3
Dividends payable | $	$ 5,100,000
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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
A reconciliation between basic and diluted earnings per share computations
Net income (loss) available to common stockholders	$ (9,659)	$ (23,306)	$ (24,143)	$ (39,137)	$ (64,696)	$ (51,910)	$ (61,083)	$ (122,240)	$ (96,245)	$ (299,929)	$ 26,051
Net income (loss) available to common stockholders (in shares)									18,354	16,256	16,051
Net income (loss) available to common stockholders (in usd per share)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (3.94)	$ (3.19)	$ (3.77)	$ (7.55)	$ (5.24)	$ (18.45)	$ 1.57
Stock options, effect of dilutive securities									$ 0	$ 0
Stock options, effect of dilutive securities, (in shares)									0	0	5
Attributable to participating securities									$ 0	$ 0	$ (854)
Restricted stock, effect of dilutive securities (in shares)									0	0	0
Attributable to participating securities											$ (855)
Net income or loss available to common stockholders, Loss (excluding income attributable to participating securities)											25,196
DILUTED EPS, Loss									$ (96,245)	$ (299,929)	$ 25,197
DILUTED EPS (in shares)									18,354	16,256	16,056
DILUTED EPS, per share amount (in usd per share)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (3.94)	$ (3.19)	$ (3.77)	$ (7.55)	$ (5.24)	$ (18.45)	$ 1.57

Earnings Per Share - Additional

Earnings Per Share - Additional Information (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock issuable on conversion (in shares)	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
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock issuable on conversion (in shares)			0.3

Share-Based Compensation - Shar

Share-Based Compensation - Share based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of share-based compensation
Share-based compensation	$ 1,687	$ 4,178	$ 8,342
Incentive Stock Options (share settled)
Summary of share-based compensation
Share-based compensation	206	243	573
Non-Qualified Stock Options (share settled)
Summary of share-based compensation
Share-based compensation	164	71	171
Restricted stock (share settled)
Summary of share-based compensation
Share-based compensation	1,073	4,303	4,504
Cash settled stock units
Summary of share-based compensation
Share-based compensation	$ 244	$ (439)	$ 3,094

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details)	1 Months Ended	12 Months Ended
	Nov. 30, 2014shares	Dec. 31, 2016USD ($)companyshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation costs capitalized in period | $		$ 100,000	$ 0	$ 1,500,000
Tax benefit from compensation expense | $		500,000	1,500,000	2,300,000
Total compensation cost not yet recognized | $		$ 1,800,000
Period for recognition		3 years
Fair value of stock options that vested during period | $		$ 400,000	$ 800,000	$ 1,000,000
Granted (in shares) | shares		0
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period until vesting		1 year
Forfeiture rate		5.00%
Granted (in shares) | shares		0
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
Exercise price percent of fair value at grant date		100.00%
Forfeiture rate		5.00%		5.00%
Cash settled stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		3 years
Granted (in shares) | shares		0
Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual vesting percentage		33.33%
Granted (in shares) | shares	60,767	0
Evaluation period (in days)		20 days
Number of peer group companies | company		12
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, 2016	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Stock options granted (shares)	1,168,754
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, minimum (as a percent)	62.00%	79.40%
Expected volatility, maximum (as a percent)	79.99%	80.00%
Risk-free rate, minimum (as a percent)	1.255%	1.81%
Risk-free rate, maximum (as a percent)	2.09%	2.015%
Expected term	6 years	6 years
Forfeiture rate	5.00%	5.00%
Stock options granted (shares)	1,168,754	17,358.5
Weighted average grant date fair value (usd per share)	$ 1.96	$ 11.36
Fair value of grants	$ 2,293	$ 197

Share-Based Compensation - Acti

Share-Based Compensation - Activity (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Number of Options
Outstanding at beginning of year (in shares) | shares	340,492
Granted (in shares) | shares	1,168,754
Expired/canceled/forfeited (in shares) | shares	(96,306)
Exercised (in shares) | shares	0
Outstanding at end of year (in shares) | shares	1,412,940
Wgtd. Avg. Exercise Price
Outstanding at beginning of year (in dollars per share) | $ / shares	$ 24.38
Granted (in dollars per share) | $ / shares	3.33
Expired/canceled/forfeited (in dollars per share) | $ / shares	22.01
Exercised (in dollars per share) | $ / shares	0
Outstanding at end of year (in dollars per share) | $ / shares	$ 7.13
Additional Disclosures
Options exercisable at end of year (in shares) | shares	256,013
Options expected to vest (in shares) | shares	1,355,094
Options exercisable at end of year (usd per share) | $ / shares	$ 24.11
Options expected to vest (usd per share) | $ / shares	$ 7.29
Outstanding, remaining contractual term	8 years 8 months 28 days
Exercisable, remaining contractual term	4 years 8 months 22 days
Vested and expected to vest, remaining contractual term	8 years 8 months 14 days
Outstanding, intrinsic value | $	$ 186
Exercisable, intrinsic value | $	0
Vested and expected to vest, intrinsic value | $	$ 176

Share-Based Compensation - Exer

Share-Based Compensation - Exercise Prices (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding at end of year (in shares)	1,412,940	340,492
Wgtd. Avg. Remaining Contractual Life	8 years 8 months 28 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 7.13	$ 24.38
Options exercisable (in shares)	256,013
Wgtd. Avg. Exercise Price (usd per share)	$ 24.11
$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)	66,373
Wgtd. Avg. Remaining Contractual Life	9 years 2 months 13 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 2.37
Options exercisable (in shares)
Wgtd. Avg. Exercise Price (usd per share)	$ 0
$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	9 years 8 months 26 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 3.17
Options exercisable (in shares)
Wgtd. Avg. Exercise Price (usd per share)	$ 0
$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	9 years 4 months 18 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 4.26
Options exercisable (in shares)
Wgtd. Avg. Exercise Price (usd per share)	$ 0
$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)	260,965
Wgtd. Avg. Remaining Contractual Life	4 years 9 months 8 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 23.94
Options exercisable (in shares)	256,013
Wgtd. Avg. Exercise Price (usd per share)	$ 24.11

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Number of Shares
Outstanding at beginning of year (in shares)	214,158
Granted (in shares)	0
Canceled/forfeited (in shares)	(47,182)
Lapse of restrictions (in shares)	(120,068)
Outstanding at end of year (in shares)	46,908	214,158
Restricted Stock
Number of Shares
Outstanding at beginning of year (in shares)	296,259
Granted (in shares)	0
Canceled/forfeited (in shares)	(67,672)
Lapse of restrictions (in shares)	(150,030)
Outstanding at end of year (in shares)	78,557	296,259
Wgtd. Avg. Fair Value per Share
Outstanding at beginning of year (in dollars per share)	$ 16.32
Granted (in dollars per share)	0	$ 5.08	$ 17.28
Canceled/forfeited (in dollars per share)	16.97
Lapse of restrictions (in dollars per share)	15.90
Outstanding at end of year (in dollars per share)	$ 16.57	$ 16.32
Additional Information
Total value of stock that vested	$ 2.4	$ 4.7	$ 5
Weighted average remaining life	1 year

Share-Based Compensation - Re52

Share-Based Compensation - Restricted Stock Units (Details) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2014shares	Dec. 31, 2016USD ($)companyshares	Dec. 31, 2015shares
Number of Shares
Outstanding at beginning of year (in shares)		214,158
Granted (in shares)		0
Canceled/forfeited (in shares)		(47,182)
Vested/Paid (in shares)		(120,068)
Outstanding at end of year (in shares)		46,908	214,158
Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Evaluation period (in days)		20 days
Number of peer group companies | company		12
Earned at end of performance period, percent			50.00%
Number of Shares
Outstanding at beginning of year (in shares)		25,821
Granted (in shares)	60,767	0
Canceled/forfeited (in shares)		(2,285)
Vested/Paid (in shares)		(8,607)
Outstanding at end of year (in shares)		14,929	25,821
Cash settled stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		3 years
Total value of stock that vested | $		$ 0.3
Number of Shares
Outstanding at beginning of year (in shares)		188,337
Granted (in shares)		0
Canceled/forfeited (in shares)		(44,897)
Vested/Paid (in shares)		(111,461)
Outstanding at end of year (in shares)		31,979	188,337
Restricted Stock Units (RSUs) and Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Liability for RSUs outstanding and expected to vest		100,000
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%

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 42,556	$ 54,970
Liabilities incurred	0	466
Liabilities settled	(3,296)	(2,776)
Accretion expense	2,515	3,259
Revisions in estimated cash flows	(1,746)	(11,137)
Divestiture of oil and gas properties	(3,419)	(2,226)
Asset retirement obligation, end of period	36,610	42,556
Less: current portion of asset retirement obligation	(4,160)	(6,015)
Long-term asset retirement obligation	32,450	36,541
Oklahoma Assets
Changes to the Company's asset retirement obligation liability
Divestiture of oil and gas properties	$ (3,300)
Woodford And Mississippian Lime
Changes to the Company's asset retirement obligation liability
Divestiture of oil and gas properties		$ (1,800)

Derivative Instruments - Volume

Derivative Instruments - Volumes and Weighted Average Price (Details) - Natural Gas - Swap	12 Months Ended
	Dec. 31, 2016MMBTU$ / shares
January 2017 - December 2017
Oil and gas contracts
Daily Volumes | MMBTU	10,000
Weighted Average Price | $ / shares	$ 3.26
January 2017 - March 2018
Oil and gas contracts
Daily Volumes | MMBTU	10,000
Weighted Average Price | $ / shares	$ 3.01
April 2017 - March 2018
Oil and gas contracts
Daily Volumes | MMBTU	10,000
Weighted Average Price | $ / shares	$ 3.40
October 2017 - March 2018
Oil and gas contracts
Daily Volumes | MMBTU	10,000
Weighted Average Price | $ / shares	$ 3.22

Derivative Instruments - Effect

Derivative Instruments - Effect of Cash Flow Hedges on the Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative liability	$ (4,800)
Designated as Hedging Instrument | Commodity Derivatives | Derivative liability
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative liability	(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)
Designated as Hedging Instrument | Commodity Derivatives | Derivative asset
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative asset		$ 1,508

Derivative Instruments - Effe56

Derivative Instruments - Effect of Cash Flow Hedges on the Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income	$ (5,697)	$ (4,473)	$ 6,516
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income	(4,447)	9,991	6,683
Designated as Hedging Instrument | Oil and gas sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified into Income	$ 1,811	$ 17,114	$ (3,044)

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative liability	$ (4.8)
Realization of gain, net of taxes	(2.5)
Gas hedges
Derivatives, Fair Value [Line Items]
Net settlement of hedges	1.8	$ 15.9	$ (4.2)
NGL hedges
Derivatives, Fair Value [Line Items]
Net settlement of hedges	0	0.5	0.3
Crude Oil
Derivatives, Fair Value [Line Items]
Net settlement of hedges	$ 0	$ 0.6	$ 0.9

Fair Value Measurements - Commo

Fair Value Measurements - Commodity Derivatives at Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
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	(4,750)	1,508
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, 2016	Dec. 31, 2015	Jul. 03, 2013	Aug. 19, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	$ 280,295,000	$ 350,000,000
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	211,894,000	238,000,000
Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	286,396,000	347,008,000
Senior Notes | 2017 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	22,650,000	350,000,000	$ 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	21,970,000	238,000,000
Senior Notes | 2017 Notes | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	22,568,000	347,008,000
Senior Notes | 2021 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	14,177,000	0
Senior Notes | 2021 Notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	12,192,000	0
Senior Notes | 2021 Notes | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	15,228,000	0
Payment in Kind (PIK) Note | 2021 PIK Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Face Value	243,468,000	0
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	177,732,000	0
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	$ 248,600,000	$ 0

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) shares in Millions	Oct. 17, 2016USD ($)	Sep. 27, 2016USD ($)paymentshares	Feb. 17, 2016USD ($)shares	Mar. 31, 2017	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 30, 2017	Sep. 30, 2016	Jan. 14, 2016	Jul. 03, 2013USD ($)	Aug. 19, 2010USD ($)
Debt Instrument [Line Items]
Principal amount					$ 280,295,000	$ 350,000,000
Amortization of debt issuance costs					(10,139,000)	0	$ 0
Deferred finance costs						(1,400,000)
10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Principal amount					$ 22,650,000	$ 350,000,000					$ 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		$ 22,568,000	$ 347,008,000
Excess (shortfall) carrying value					0	0
Deferred finance costs					(82,000)	(2,992,000)
10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Principal amount					$ 14,177,000	0
Stated interest rate (as a percent)					10.00%
Long-term debt					$ 15,228,000	0
Excess (shortfall) carrying value					1,159,000	0
Deferred finance costs					(108,000)	0
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Principal amount					$ 243,468,000	0
Stated interest rate (as a percent)					10.00%
Long-term debt					$ 248,600,000	0
Excess (shortfall) carrying value					(590,000)	0
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]
Stated interest rate (as a percent)									10.00%
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					(1,500,000)
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)
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%
September Exchange And Consent Solicitation | Scenario, Forecast | 10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Redemption price, percentage				100.00%
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					10,000,000	0
Long-term debt					7,249,000	0
Excess (shortfall) carrying value					0	0
Deferred finance costs					(2,751,000)	$ 0
Term Loan | Loan Agreement | Line of Credit
Debt Instrument [Line Items]
Stated interest rate (as a percent)	10.00%
Long-term debt					$ 10,000,000
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					1.7
Term Loan | Scenario, Forecast | Loan Agreement | Line of Credit
Debt Instrument [Line Items]
Ratio of present value of estimated future net revenues to sum of outstanding term loans and commitments				1.7				2

Long-Term Debt - Face Value to

Long-Term Debt - Face Value to Carrying Value Reconciliation (Details) - USD ($)	Dec. 31, 2016	Feb. 17, 2016	Dec. 31, 2015	Jul. 03, 2013	Aug. 19, 2010
Debt Instrument [Line Items]
Principal amount	$ 280,295,000		$ 350,000,000
Unamortized deferred finance costs			(1,400,000)
Senior Notes | 10% Senior Unsecured Notes Due 2017
Debt Instrument [Line Items]
Principal amount	22,650,000		350,000,000	$ 200,000,000	$ 150,000,000
Unamortized deferred finance costs	(82,000)		(2,992,000)
Excess (shortfall) Carrying Value	0		0
Long-term debt	22,568,000	$ 135,600,000	347,008,000
Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Principal amount	14,177,000		0
Unamortized deferred finance costs	(108,000)		0
Excess (shortfall) Carrying Value	1,159,000		0
Long-term debt	15,228,000		0
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Principal amount	243,468,000		0
Unamortized deferred finance costs	0		0
Excess (shortfall) Carrying Value	(590,000)		0
Accrued PIK Interest	5,722,000		0
Long-term debt	248,600,000		0
Term Loan | Line of Credit
Debt Instrument [Line Items]
Principal amount	10,000,000		0
Unamortized deferred finance costs	(2,751,000)		0
Excess (shortfall) Carrying Value	0		0
Long-term debt	$ 7,249,000		$ 0

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Total joint interest billing receivable (less than 1%)	1.00%
Officer [Member]
Related Party Transaction [Line Items]
Joint interest billing receivables	$ 8,000
Goodson
Related Party Transaction [Line Items]
Proceeds from affiliates	(15,000)	$ (45,000)
Payments of distributions to related parties			$ 80,000
Related expenses related to transactions with related party	0	0	18,000
Green
Related Party Transaction [Line Items]
Payments of distributions to related parties	25,000	30,000	$ 116,000
Nordberg
Related Party Transaction [Line Items]
Due from affiliates	$ (200)	$ (300)

Ceiling Test Write-down (Detail

Ceiling Test Write-down (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / mcf$ / bbl$ / Mcfe	Dec. 31, 2015USD ($)$ / mcf$ / bbl$ / Mcfe	Dec. 31, 2014USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Ceiling test write-down	$ 40,304	$ 266,562	$ 0
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
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		$ 1,100

Other Comprehensive Income (L64

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

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes (Textual) [Abstract]
Income taxes at a statutory rate	35.00%	35.00%	35.00%
Cumulative loss period	3 years
Valuation allowance	$ 177,405	$ 143,508
Operating loss carryforwards	260,100
Operating loss carryforwards subject to expiration (in 2025)	6,900
Share-based Compensation
Income Taxes (Textual) [Abstract]
Operating loss carryforwards	12,600
Depletion Deduction
Income Taxes (Textual) [Abstract]
Depletion deduction carryforward	$ 26,800

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 92,072	$ 51,519
Percentage depletion carryforward	9,372	10,592
Alternative minimum tax credits	784	784
Contributions carryforward and other	282	266
Oil and gas properties	27,992	62,786
Asset retirement obligation	13,620	15,831
Derivatives	1,767	(561)
Share-based compensation	1,870	2,291
Original issue discount on debt exchanges	29,646	0
Valuation allowance	(177,405)	(143,508)
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Amount computed using the statutory rate	$ (31,623)	$ (102,257)	$ 9,887
State & local taxes	(2,000)	(6,477)	904
Percentage depletion carryforward	(163)	(404)	(1,564)
Non-deductible stock option expense	77	90	213
Share-based compensation	707	1,317	90
Other	1,415	113	(643)
Change in valuation allowance	32,130	110,244	(11,828)
Income tax expense (benefit)	$ 543	$ 2,626	$ (2,941)

Commitments and Contingencies68

Commitments and Contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,017	$ 1,208
2,018	470
2,019	447
2,020	445
2,021	434
Thereafter	811
Total	3,815
Operating leases rent expense	$ 1,500	$ 1,700	$ 1,600

Supplementary Information on 69

Supplementary Information on Oil and Gas Operations-Unaudited - Costs Incurred (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / Mcfe	Dec. 31, 2015USD ($)$ / Mcfe	Dec. 31, 2014USD ($)$ / Mcfe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Acquisition costs: Proved	$ 3,346	$ 2,287	$ 3,064
Acquisition costs: Unproved	2,197	2,550	39,164
Divestiture of proved leasehold	(7,000)	0	0
Exploration costs: Proved	715	29,322	67,297
Exploration costs: Unproved	603	7,677	13,515
Development costs	1,522	9,888	55,722
Capitalized general and administrative and interest costs	7,558	12,881	22,121
Total costs incurred	8,941	64,605	200,883
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	(1,157,455)	(1,648,060)	(1,553,044)
Provision for DD&A	(27,962)	(62,138)	(86,406)
Ceiling test writedown	(40,304)	(266,562)	0
Sale of proved properties and other	(17,565)	819,305	(8,610)
Balance, end of year	$ (1,243,286)	$ (1,157,455)	$ (1,648,060)
DD&A per Mcfe (usd per mcfe) | $ / Mcfe	1.19	1.82	1.99

Supplementary Information on 70

Supplementary Information on Oil and Gas Operations-Unaudited - Investment in Oil and Gas Properties (Details) a in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)Wells	Dec. 31, 2015USD ($)aWells	Dec. 31, 2014USD ($)
Reserve Quantities [Line Items]
Sale of oil and gas properties	$ 25,482	$ 271,769	$ 11,908
Unevaluated oil and gas properties	9,000	12,500
Interest costs capitalized	$ 900	4,700	10,000
Expected period to evaluate existing unevaluated properties	3 years
Unevaluated costs expected to be evaluated in 2017	$ 1,800
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
Eagle Ford
Reserve Quantities [Line Items]
Sale of oil and gas properties			9,800
Uncompleted Wells Equipment and Facilities
Reserve Quantities [Line Items]
Unevaluated oil and gas properties	$ 400	$ 200
Exploratory wells drilled, unevaluated | Wells	1	2
2,012
Reserve Quantities [Line Items]
Unevaluated oil and gas properties	$ 3,400
Percentage of unevaluated costs capitalized in period	38.00%
2,011
Reserve Quantities [Line Items]
Unevaluated oil and gas properties		$ 1,100
Percentage of unevaluated costs capitalized in period		12.00%
Prior to 2011
Reserve Quantities [Line Items]
Unevaluated oil and gas properties			$ 4,500
Percentage of unevaluated costs capitalized in period			50.00%
Louisiana | Fleetwood Joint Venture
Reserve Quantities [Line Items]
Aggregate purchase price		$ 24,000
Number of acres acquired | a		30
Woodford And Mississippian Lime
Reserve Quantities [Line Items]
Sale of oil and gas properties	$ 274,100
Oklahoma Assets
Reserve Quantities [Line Items]
Sale of oil and gas properties	$ 17,600

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, 2016McfeMBblsMMcf	Dec. 31, 2015McfeMBblsMMcf	Dec. 31, 2014McfeMBblsMMcf
Oil
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MBbls	1,806	2,437	3,031
Revisions of previous estimates | MBbls	247	(211)	(37)
Extensions, discoveries and other additions | MBbls	0	163	475
Sale of reserves in place | MBbls	(154)	(54)	(229)
Production | MBbls	(502)	(529)	(803)
Proved reserves ending balance | MBbls	1,397	1,806	2,437
Proved developed reserves | MBbls	1,212	1,549	2,089
Proved undeveloped reserve | MBbls	185	257	348
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	34,826	73,498	28,430
Revisions of previous estimates	(4,380)	(3,571)	2,894
Extensions, discoveries and other additions	0	16,078	49,990
Sale of reserves in place	0	(45,692)	(334)
Production	(3,871)	(5,487)	(7,482)
Proved reserves, ending balance	26,575	34,826	73,498
Proved undeveloped reserve	13,073	15,792	42,584
Proved developed reserves	13,502	19,034	30,914
Natural Gas
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MMcf	132,344	309,025	250,109
Revisions of previous estimates | MMcf	(11,854)	(9,852)	9,976
Extensions, discoveries and other additions | MMcf	1,485	45,645	82,364
Sale of reserves in place | MMcf	(24,834)	(186,972)	(2,396)
Production | MMcf	(16,617)	(25,502)	(31,028)
Proved reserves ending balance | MMcf	80,524	132,344	309,025
Proved developed reserves | MMcf	47,349	78,533	182,567
Proved undeveloped reserve | MMcf	33,175	53,811	126,458
Oil and Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	178,004	397,148	296,723
Revisions of previous estimates	(14,748)	(14,698)	12,650
Extensions, discoveries and other additions	1,485	62,702	135,205
Sale of reserves in place	(25,759)	(232,988)	(4,105)
Production	(23,501)	(34,160)	(43,325)
Proved reserves, ending balance	115,481	178,004	397,148
Proved undeveloped reserve	67,694	103,615	237,688
Proved developed reserves	47,787	74,389	159,460

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, 2016McfeWells$ / mcf$ / bbl$ / McfeMBblsMMcf	Dec. 31, 2015McfeWells$ / mcf$ / bbl$ / McfeMBblsMMcf	Dec. 31, 2014McfeWells$ / mcf$ / bbl$ / McfeMBblsMMcf
Reserve Quantities [Line Items]
Company drilling success rate	100.00%	95.00%	91.00%
Gross wells drilled | Wells	5	56	58
Oklahoma
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)		17,000	72,000
Texas
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)		44,000	46,000
Gulf Coast
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)			15,000
Oil
Reserve Quantities [Line Items]
Number of Bcfe additions | MBbls	0	163	475
Consolidated oil and gas production costs per unit of production | $ / bbl	40.85	50.29	96.45
Natural Gas Liquids
Reserve Quantities [Line Items]
Extensions, discoveries and other additions of Bcfe	0	16,078	49,990
Consolidated oil and gas production costs per unit of production | $ / Mcfe	2.40	2.24	4.11
Oil and Natural Gas Reserves
Reserve Quantities [Line Items]
Increase in proved developed and undeveloped reserves	(35.00%)	(55.17909%)	33.84053%
Extensions, discoveries and other additions of Bcfe	1,485	62,702	135,205
Natural Gas
Reserve Quantities [Line Items]
Number of Bcfe additions | MMcf	1,485	45,645	82,364
Consolidated oil and gas production costs per unit of production | $ / mcf	1.82	2.41	3.80

Supplementary Information on 73

Supplementary Information on Oil and Gas Operations-Unaudited - Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows [Abstract]
Future cash flows	$ 299,035	$ 487,834	$ 1,711,404
Future production costs	(117,283)	(171,678)	(372,690)
Future development costs	(83,720)	(116,591)	(244,784)
Future income taxes	0	0	(121,192)
Future net cash flows	98,032	199,565	972,738
10% annual discount	(30,763)	(71,880)	(424,176)
Standardized measure of discounted future net cash flows	$ 67,269	$ 127,685	$ 548,562	$ 451,180

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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 127,685	$ 548,562	$ 451,180
Sales and transfers of oil and gas produced, net of production costs	(35,993)	(55,849)	(173,540)
Changes in price, net of future production costs	(30,427)	(267,710)	37,204
Extensions and discoveries, net of future production and development costs	864	70,928	237,290
Changes in estimated future development costs, net of development costs incurred during this period	26,356	31,007	11,094
Revisions of quantity estimates	(14,889)	(14,427)	25,591
Accretion of discount	12,769	60,071	47,130
Net change in income taxes	0	52,149	(32,034)
Sale of reserves in place	(16,701)	(194,454)	(7,240)
Changes in production rates (timing) and other	(2,395)	(102,592)	(48,113)
Net increase (decrease) in standardized measure	(60,416)	(420,877)	97,382
Standardized measure at end of year	$ 67,269	$ 127,685	$ 548,562

Summarized Quarterly Financia75

Summarized Quarterly Financial Information-Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 16,429	$ 17,094	$ 15,824	$ 17,320	$ 23,096	$ 26,872	$ 32,550	$ 33,451
Loss from operations	(8,374)	(22,039)	(22,383)	(37,557)	(61,864)	(50,617)	(57,796)	(121,887)	$ (90,353)	$ (292,164)	$ 28,249
Loss available to common stockholders	$ (9,659)	$ (23,306)	$ (24,143)	$ (39,137)	$ (64,696)	$ (51,910)	$ (61,083)	$ (122,240)	$ (96,245)	$ (299,929)	$ 26,051
Earnings per share, Basic (in usd per share)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (3.94)	$ (3.19)	$ (3.77)	$ (7.55)	$ (5.24)	$ (18.45)	$ 1.57
Earnings per share, Diluted (in usd per share)	$ (0.46)	$ (1.31)	$ (1.38)	$ (2.09)	$ (3.94)	$ (3.19)	$ (3.77)	$ (7.55)	$ (5.24)	$ (18.45)	$ 1.57
Ceiling test write-downs		$ 8,700	$ 12,800	$ 18,900	$ 51,900	$ 40,200	$ 65,500	$ 108,900
Gain on sale of assets							$ 21,500		$ 0	$ 21,937	$ 0