Petroquest Energy (PQ) 10-K 4 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Feb. 26, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	872,248
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		70,534,569
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 84,213

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 148,013	$ 18,243
Revenue receivable	6,476	16,485
Joint interest billing receivable	49,374	46,778
Derivative asset	1,508	8,631
Other current assets	3,874	6,413
Total current assets	209,245	96,550
Oil and gas properties:
Oil and gas properties, full cost method	1,310,891	2,222,753
Unevaluated oil and gas properties	12,516	109,119
Accumulated depreciation, depletion and amortization	(1,157,455)	(1,648,060)
Oil and gas properties, net	165,952	683,812
Other property and equipment	11,229	14,953
Accumulated depreciation of other property and equipment	(8,737)	(10,313)
Total property and equipment	168,444	688,452
Other assets, net of accumulated amortization of $3,842 and $3,448, respectively	1,630	1,106
Total assets	379,319	786,108
Current liabilities:
Accounts payable to vendors	97,999	102,954
Advances from co-owners	16,118	12,819
Oil and gas revenue payable	18,911	22,333
Accrued interest and preferred stock dividend	12,795	12,764
Asset retirement obligation	6,015	2,756
Accrued acquisition costs	4,409	17,690
Other accrued liabilities	2,537	5,394
Total current liabilities	158,784	176,710
Bank debt		75,000
10% Senior Notes	347,008	345,213
Asset retirement obligation	36,541	52,214
Other long-term liability	$ 53	$ 62
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 65,641 and 64,721 shares, respectively	66	65
Paid-in capital	290,382	285,957
Accumulated other comprehensive income	947	5,420
Accumulated deficit	(454,463)	(154,534)
Total stockholders’ equity	(163,067)	136,909
Total liabilities and stockholders’ equity	$ 379,319	$ 786,108

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Accumulated depreciation and amortization	$ 3,842	$ 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	65,641,000	64,721,000
Common stock, shares outstanding	65,641,000	64,721,000
10% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate (as a percent)	10.00%	10.00%

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil and gas sales	$ 115,969	$ 225,021	$ 182,804
Expenses:
Lease operating expenses	40,130	48,597	43,743
Production taxes	2,470	5,927	3,950
Depreciation, depletion and amortization	63,497	87,818	71,445
Ceiling test write-down	266,562	0	0
General and administrative	20,777	22,870	26,512
Accretion of asset retirement obligation	3,259	2,958	1,753
Interest expense	33,766	29,281	21,886
Total expenses	430,461	197,451	169,289
Other income:
Gain on sale of assets	21,937	0	0
Other income	391	679	654
Derivative income	0	0	233
Other income (expense), net	22,328	679	887
Income (loss) from operations	(292,164)	28,249	14,402
Income tax expense (benefit)	2,626	(2,941)	320
Net income (loss)	(294,790)	31,190	14,082
Preferred stock dividend	5,139	5,139	5,139
Net income (loss) available to common stockholders	$ (299,929)	$ 26,051	$ 8,943
Basic
Net income (loss) per share (in usd per share)	$ (4.61)	$ 0.39	$ 0.14
Diluted
Net income (loss) per share (in usd per share)	$ (4.61)	$ 0.39	$ 0.14
Weighted average number of common shares:
Basic (shares)	65,022	64,204	63,054
Diluted (shares)	65,022	64,225	63,208

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (294,790)	$ 31,190	$ 14,082
Change in fair value of derivatives, net of income tax (expense) benefit of $2,650, ($3,211) and $309 respectively	(4,473)	6,516	(1,617)
Comprehensive income (loss)	$ (299,263)	$ 37,706	$ 12,465

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net of income taxes	$ (2,650)	$ 3,211	$ (309)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (294,790)	$ 31,190	$ 14,082
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)	2,626	(2,941)	320
Depreciation, depletion and amortization	63,497	87,818	71,445
Ceiling test write-down	266,562	0	0
Accretion of asset retirement obligation	3,259	2,958	1,753
Share based compensation expense	4,617	5,248	4,216
Gain on sale of assets	(21,937)	0	0
Amortization costs and other	2,259	2,188	1,473
Non-cash derivative income	0	0	(233)
Payments to settle asset retirement obligations	(2,776)	(3,623)	(3,335)
Changes in working capital accounts:
Revenue receivable	10,009	10,083	(8,826)
Prepaid drilling and pipe costs	0	(370)	1,221
Joint interest billing receivable	223	(20,276)	15,685
Accounts payable and accrued liabilities	(9,400)	50,243	(12,865)
Advances from co-owners	3,299	11,850	(19,490)
Other	2,657	3,840	(5,592)
Net cash provided by operating activities	30,105	178,208	59,854
Cash flows provided by (used in) investing activities:
Investment in oil and gas properties	(90,218)	(174,633)	(298,824)
Investment in other property and equipment	(454)	(926)	(1,679)
Sale of oil and gas properties	271,769	11,908	20,400
Net cash provided by (used in) investing activities	181,097	(163,651)	(280,103)
Cash flows provided by (used in) financing activities:
Net payments for share based compensation	(199)	(75)	(38)
Deferred financing costs	(1,094)	(253)	(320)
Payment of preferred stock dividend	(5,139)	(5,139)	(5,139)
Proceeds from bank borrowings	70,000	17,500	73,000
Repayment of bank borrowings	(145,000)	(17,500)	(48,000)
Proceeds from issuance of 10% Senior Notes	0	0	200,000
Costs to issue 10% Senior Notes	0	0	(5,005)
Net cash provided by (used in) financing activities	(81,432)	(5,467)	214,498
Net increase (decrease) in cash and cash equivalents	129,770	9,090	(5,751)
Cash and cash equivalents, beginning of period	18,243	9,153	14,904
Cash and cash equivalents, end of period	148,013	18,243	9,153
Cash paid during the period for:
Interest	36,217	37,174	20,101
Income taxes	$ 0	$ 270	$ 12

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Preferred Stock	Paid-In Capital	Other Comprehensive Income (Loss)	Accumulated Deficit
Beginning stockholders' equity at Dec. 31, 2012	$ 87,591	$ 63	$ 1	$ 276,534	$ 521	$ (189,528)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Options exercised	731			731
Retirement of shares upon vesting of restricted stock	(1,056)	1		(1,057)
Share-based compensation expense	4,216			4,216
Issuance of shares under employee stock purchase plan	287			287
Derivative fair value adjustment, net of tax	(1,617)				(1,617)
Preferred stock dividend	(5,139)					(5,139)
Net income (loss)	14,082					14,082
Ending stockholders' equity at Dec. 31, 2013	99,095	64	1	280,711	(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)	1		(1,310)
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 stockholders' equity at Dec. 31, 2014	136,909	65	1	285,957	5,420	(154,534)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Options exercised	61			61
Retirement of shares upon vesting of restricted stock	(451)	1		(452)
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 stockholders' equity at Dec. 31, 2015	$ (163,067)	$ 66	$ 1	$ 290,382	$ 947	$ (454,463)

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 exploration offices in The Woodlands, Texas and Tulsa, Oklahoma. It is engaged in the exploration, development, acquisition and operation of oil and gas properties in Texas and the Gulf Coast Basin, as well as in Oklahoma. 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. 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 first of the month average twelve-month 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 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. During 2012, a field office servicing the Company's Oklahoma assets was built and is being depreciated over 39 years. Other Assets Other assets at December 31, 2015 and 2014 included $1.4 million and $0.7 million , respectively, related to deferred financing costs with respect to the Company's bank credit facility, which are amortized on a straight-line basis over the life of the 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 which 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 realizabilty 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, 2015 2014 2013 Laclede Energy 21% 24% 14% Shell Trading Co. 18% 30% 35% Unimark, LLC 17% 14% 14% BG Group 10% (a) (a) (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 cash settlements of hedges are recorded as adjustments to oil and gas sales. Oil and gas revenues include additions (reductions) related to the net settlement of hedges totaling $17.1 million , ($3.0) million and $0.9 million during 2015 , 2014 and 2013 , respectively. The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2015 , the Company’s derivative instruments were designated as effective cash flow hedges. See Note 8 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. Early application is not permitted. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. The Company 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 April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs", which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt liability rather than as an asset. Additionally, in August 2015, the FASB issued ASU No. 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which was issued to clarify the guidance with respect to the presentation of debt issuance costs related to line-of-credit arrangements. ASU 2015-15 clarifies that the SEC staff would not object to an entity deferring and presenting such debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company has elected to early adopt this standard effective December 31, 2015. As a result, deferred financing costs, net of accumulated amortization, related to the Company's 10% Senior Notes due 2017 of $3.0 million and $4.8 million as of December 31, 2015 and 2014 , respectively, were reclassified from other assets to a direct reduction from the carrying amount of the related debt.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Acquisitions: Gulf of Mexico On July 3, 2013, the Company acquired certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired Assets”), for an aggregate cash purchase price of $188.8 million , reflecting an effective date of January 1, 2013 (collectively, the "Gulf of Mexico Acquisition"). The Acquired Assets included 16 gross wells located on seven platforms. The aggregate cash purchase price of the Gulf of Mexico Acquisition was financed with the net proceeds from the sale of $200 million in aggregate principal amount of the Company's 10% Senior Notes due 2017 . In connection with the transaction, the Company recorded $5 million of deferred financing costs and incurred $4.0 million of acquisition-related costs, including $2.6 million related to a bridge commitment fee, which were recognized as general and administrative expenses during 2013. The Gulf of Mexico Acquisition was accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The fair value of proved and unevaluated oil and gas properties was estimated using the income approach based on estimated reserve quantities, costs to produce and develop reserves, and forward prices for oil and gas, which represent Level 2 and Level 3 inputs. Asset retirement obligations were determined in accordance with applicable accounting standards. The following table summarizes the acquisition date fair values of the net assets acquired (in thousands): Oil and gas properties $ 192,067 Unevaluated oil and gas properties 12,033 Asset retirement obligations (15,319 ) Net assets acquired $ 188,781 The following unaudited summary pro forma financial information for the twelve month periods ended December 31, 2013 has been prepared to give effect to the Gulf of Mexico Acquisition as if it had occurred on January 1, 2012. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2012 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following unaudited pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors. Amounts are presented in thousands, except per share amounts. Twelve Months Ended December 31, 2013 Revenues $ 215,666 Income from Operations 19,858 Net Income available to common stockholders 14,399 Basic Earnings per Share $ 0.22 Diluted Earnings per Share $ 0.22 Fleetwood Joint Venture In June 2014, we entered into a joint venture in Louisiana for an aggregate purchase price of $24 million . The assets acquired under the joint venture include an average 37% working interest in an approximately 30,000 acre leasehold position in Louisiana and exclusive rights, along with our joint venture partner, to a 200 square mile proprietary 3D survey which has generated several conventional and shallow non-conventional oil focused prospects. The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. At December 31, 2015 , $4.4 million of this drilling carry remained outstanding. The liability is reflected as accrued acquisition costs in the Consolidated Balance Sheet. During February 2016, the Company paid $4.4 million to settle this liability with its joint venture partner in connection with the terms of the agreement. Divestiture: On June 4, 2015 , the Company completed the sale of a majority of its interests in the Woodford and Mississippian Lime (the “Oklahoma Divestiture”) 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 will retain a minimal working interest in the Sold Assets and will provide certain services as a contract operator for a period of one year from the closing date of the sale, subject to renewal for two additional one -year terms. At December 31, 2014, the estimated proved reserves attributable to the Oklahoma Divestiture 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 divestiture of the Oklahoma Divestiture 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.

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event On January 14, 2016 the Company announced the commencement of a private exchange offer (the "Exchange Offer") and consent solicitation (the "Consent Solicitation") to certain eligible holders for up to $300 million aggregate principal amount of its outstanding 10% Senior Notes due 2017 (the "Old Notes") for up to (i) $75 million in cash, (ii) $202.5 million aggregate principal amount of its newly issued 10% Second Lien Senior Secured Notes due 2021 (the "New Notes"), and (iii) 6 million shares of its common stock. The Exchange Offer and Consent Solicitation were made upon the terms and subject to the conditions set forth in the Confidential Offering Memorandum and Consent Solicitation Statement (the "Offering Memorandum") and related letter of transmittal and consent, each dated January 14, 2016 . The Exchange Offer and Consent Solicitation closed on February 17, 2016 , and in satisfaction of the consideration for $214.4 million in aggregate principal amount of the Old Notes, representing approximately 61% of the outstanding aggregate principal amount of Old Notes, validly tendered (and not validly withdrawn) in the Exchange Offer, the Company (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of New Notes and (iii) issued 4,287,580 shares of its common stock. Following the completion of the Exchange Offer, $135.6 million in aggregate principal amount of the Old Notes remain outstanding. The Consent Solicitation eliminates or waives substantially all of the restrictive covenants contained in the indenture governing the Old Notes. The indenture governing the New Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the New 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 New Notes are fully and unconditionally guaranteed on a senior basis by certain wholly-owned subsidiaries of the Company. The Company will pay 10% interest per annum on the principal amount of the New Notes, semi-annually in arrears on February 15 and August 15 of each year. The New Notes are secured 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 Credit 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 New Notes and the guarantees are contractually subordinated to liens that secure the Credit Agreement and certain other permitted indebtedness. Consequently, the New Notes and the guarantees will be effectively subordinated to the Credit Agreement and such other indebtedness to the extent of the value of such assets.

Convertible Preferred Stock

Convertible Preferred Stock	12 Months Ended
	Dec. 31, 2015
Temporary Equity Disclosure [Abstract]
Convertible Preferred Stock	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. On January 26, 2016, in connection with an amendment to the Company's bank credit facility prohibiting the Company from declaring or paying dividends on the Series B Preferred Stock, the Company announced its intention to suspend 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. 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. 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 3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share of common stock, subject to 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, 2015
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, 2015 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (299,929 ) 65,022 $ (4.61 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (299,929 ) 65,022 $ (4.61 ) For the Year Ended December 31, 2014 Income(Numerator) Shares Per Net income available to common stockholders $ 26,051 64,204 Attributable to participating securities (855 ) — BASIC EPS $ 25,196 64,204 $ 0.39 Net income available to common stockholders $ 26,051 64,204 Effect of dilutive securities: Stock options — 21 Attributable to participating securities (854 ) — DILUTED EPS $ 25,197 64,225 $ 0.39 For the Year Ended December 31, 2013 Income(Numerator) Shares Per Net income available to common stockholders $ 8,943 63,054 Attributable to participating securities (257 ) — BASIC EPS $ 8,686 63,054 $ 0.14 Net income available to common stockholders $ 8,943 63,054 Effect of dilutive securities: Stock options — 154 Attributable to participating securities (256 ) — DILUTED EPS $ 8,687 63,208 $ 0.14 An aggregate of 0.3 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 5.1 million shares were not included in the computation of diluted earnings per share for 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 5.1 million shares during 2014 and 2013 were not included in the computation of diluted earnings per share because the inclusion would have been anti-dilutive. Options to purchase 1.0 million and 1.2 million shares of common stock were outstanding during the year ended December 31, 2014 and 2013 , respectively, 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, 2015
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, 2015 , 2014 and 2013 is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Stock options: Incentive Stock Options (share settled) $ 243 $ 573 $ 310 Non-Qualified Stock Options (share settled) 71 171 222 Restricted stock (share settled) 4,303 4,504 3,684 Cash settled stock units (439 ) 3,094 1,611 Share-based compensation $ 4,178 $ 8,342 $ 5,827 During the years ended December 31, 2014 and 2013 , the Company capitalized $1.5 million and $0.8 million of compensation cost related to cash settled restricted stock units to oil and gas properties. No such amounts were capitalized during the year ended December 31, 2015 . During the years ended December 31, 2015 , 2014 and 2013 , the Company recorded income tax benefits of approximately $1.5 million , $2.3 million and $1.8 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 stock At December 31, 2015 , the Company had $2.3 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 two years . Stock Options Stock options generally vest equally over a three -year period, must be exercised within 10 years of the grant date and may be granted only to employees, directors and consultants. 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 2014 and 2013 : Years Ended December 31, 2014 2013 Dividend yield —% —% Expected volatility 79.4% - 80.0% 79.6% - 79.8% Risk-free rate 1.81% - 2.015% 0.9% - 1.815% Expected term 6 years 6 years Forfeiture rate 5.0% 5.0% Stock options granted (1) 69,434 395,642 Wgtd. avg. grant date fair value per share $2.84 $2.91 Fair value of grants (1) $197,000 $1,150,000 (1) Prior to applying estimated forfeiture rate The following table details stock option activity during the year ended December 31, 2015 : Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Remaining Life Aggregate Intrinsic Value (000’s) Outstanding at beginning of year 1,517,704 $ 6.05 Granted — — Expired/cancelled/forfeited (155,680 ) 5.70 Exercised — — Outstanding at end of year 1,362,024 6.09 5.6 years $ — Options exercisable at end of year 1,217,486 $ 6.33 4.4 years $ — Options expected to vest 137,311 4.13 7.9 years $ — The total fair value of stock options that vested during the years ended December 31, 2015 , 2014 and 2013 was $0.8 million , $1.0 million and $0.8 million , respectively. The intrinsic value of stock options exercised was immaterial for all periods presented. The following table summarizes information regarding stock options outstanding at December 31, 2015 : Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg. Exercise Outstanding Remaining Exercise Exercisable Exercise Price 12/31/2015 Contractual Life Price 12/31/2015 Price $2.24—$4.48 386,908 7.8 years $4.13 251,701 $4.16 $4.49—$6.72 220,487 5.7 years $5.46 211,156 $5.48 $6.73—$8.96 744,629 4.5 years $7.25 744,629 $7.25 $8.97—$11.20 10,000 0.1 years $9.99 10,000 $9.99 1,362,024 5.6 years $6.09 1,217,486 $6.33 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 prior to 2011 generally vests over a five -year period with one-fourth vesting on each of the first, second, third and fifth anniversaries of the date of the grant. No portion of the restricted stock vests on the fourth anniversary of the date of the grant. Beginning in 2011, restricted stock granted to employees generally vests evenly over a three year period. Prior to 2013, restricted stock granted to directors generally vested evenly over a three -year period. Beginning in 2013, restricted stock granted to directors vests one year 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, 2015 : Number of Shares Wgtd. Avg. Fair Value per Share Outstanding at beginning of year 2,428,202 $ 4.37 Granted 54,717 1.27 Cancelled/forfeited (187,730 ) 3.88 Lapse of restrictions (1,110,013 ) 4.27 Outstanding at December 31, 2015 1,185,176 $ 3.81 The weighted average grant date fair value of restricted stock granted during the years ended December 31, 2015 , 2014 and 2013 was $1.27 , $4.32 and $4.18 , respectively, per share. The total fair value of restricted stock that vested during the years ended December 31, 2015 , 2014 and 2013 was $4.7 million , $5.0 million and $5.4 million , respectively. At December 31, 2015 , the weighted average remaining life of restricted stock outstanding was approximately three years and the intrinsic value of restricted stock outstanding, using the closing stock price on December 31, 2015 , was $0.6 million . Share-Based Compensation settled in cash Restricted Stock Units The Company grants 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 2015 , the Company paid $0.7 million for 0.7 million units that vested during the period. Market Based Restricted Stock Units The Company granted 243,067 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, 2015 , the Company had a liability for RSUs and MRSUs outstanding in the amount of $0.2 million based upon the closing stock price at December 31, 2015 . The following table details MRSU and RSU activity during the year ended December 31, 2015 : MRSU RSU Total Outstanding at beginning of year 243,067 1,379,261 1,622,328 Granted — 182,505 182,505 Expired/Cancelled/Forfeited (139,784 ) (120,438 ) (260,222 ) Vested/Paid — (687,704 ) (687,704 ) Outstanding at December 31, 2015 103,283 753,624 856,907

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Asset retirement obligation, beginning of period $ 54,970 $ 48,536 Liabilities incurred 466 756 Liabilities settled (5,002 ) (3,623 ) Accretion expense 3,259 2,958 Revisions in estimated cash flows (11,137 ) 6,343 Asset retirement obligation, end of period 42,556 54,970 Less: current portion of asset retirement obligation (6,015 ) (2,756 ) Long-term asset retirement obligation $ 36,541 $ 52,214 Liabilities settled during 2015 included $1.8 million as a result of the sale of our Woodford and Mississippian Lime assets.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 , 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 $15,940,000 , ($4,237,000) and $1,098,000 , Ngl hedges of $530,000 , $296,000 and $61,000 , and oil hedges of $644,000 , $897,000 and ($232,000) , for the years ended December 31, 2015 , 2014 and 2013 , respectively. As of December 31, 2015 , the Company had entered into the following gas hedge contract: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: January 2016 - June 2016 Swap 10,000 Mmbtu $3.22 At December 31, 2015 , the Company had recognized an asset of approximately $1.5 million related to the estimated fair value of this derivative contract. Based on estimated future commodity prices as of December 31, 2015 , the Company would realize a $0.9 million gain, net of taxes, during the next 12 months. This gain is expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts. During January 2016, the Company entered into the following additional derivative contract accounted for as a cash flow hedge: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: July 2016 - December 2016 Swap 5,000 Mmbtu $2.50 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, 2015 and December 31, 2014 : Commodity Derivatives Period Balance Sheet Fair Value December 31, 2015 Derivative asset $ 1,508 December 31, 2014 Derivative asset $ 8,631 Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2015 , 2014 and 2013 : Instrument Amount of Gain (Loss) Location of Amount of Gain (Loss) Reclassified into 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 ) Commodity Derivatives at December 31, 2013 $ (999 ) Oil and gas sales $ 927 Derivatives not designated as hedging instruments: The Company’s three-way collar contract for 2013 gas production was not designated as an effective cash flow hedge and therefore the gain on this contract was recorded as derivative income in the statement of operations. The following table reflects the effect of this contract in the consolidated statements of operations (in thousands): Effect of Non-designated Derivative Instrument on the Consolidated Statement of Operations for the year ended December 31, 2013 : Instrument Amount of Gain Commodity Derivatives at December 31, 2013 $ 233

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 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, 2015 and December 31, 2014 (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, 2015 $ — $ 1,508 $ — At December 31, 2014 $ — $ 8,631 $ — The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at December 31, 2015 and 2014 . The fair value of the Company's $350 million of 10% Senior Notes due 2017 (the "Notes") was approximately $238 million and $301 million as of December 31, 2015 and 2014 , respectively. The fair value of the Notes was determined based upon a market quote provided by an independent broker, which represents a Level 2 input.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt On August 19, 2010, the Company issued $150 million in principal amount of the Notes and on July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively, the "Notes"). The Notes are guaranteed by certain of PetroQuest's subsidiaries. The subsidiary guarantors are 100% owned by PetroQuest and all guarantees are full and unconditional and joint and several. PetroQuest has no independent assets or operations and the subsidiaries not providing guarantees are minor, as defined by the rules of the Securities and Exchange Commission. Interest is payable semi-annually on March 1 and September 1. At December 31, 2015 , $11.7 million had been accrued in connection with the March 1, 2016 interest payment (which amount was reduced to $4.5 million as a result of the Exchange Offering) and the Company was in compliance with all of the covenants contained in the Notes. The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of the Company’s 10% Senior Notes due 2017 remains outstanding as of such date that has not been refinanced with either permitted refinancing debt or permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement. As of December 31, 2015 the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement. The borrowing base under the Credit Agreement is determined by March 31 and September 30 of each year and based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. As of December 31, 2015 , the borrowing base was $55 million (subject to the aggregate commitments of the lenders then in effect and the Company's compliance with the financial covenants thereunder). During January 2016, the borrowing base and the aggregate commitments of the lenders were reduced to $42 million . Based on the Company's expectations for the first quarter of 2016, the Company anticipates that, pursuant to the applicable financial covenants, the Company's utilization of the borrowing base will be limited to 25% of the aggregate commitments of the lenders, or $10.5 million . The next scheduled borrowing base redetermination is scheduled to occur by March 31, 2016 with additional interim redeterminations to occur on July 31 and December 31 of each year commencing on July 31, 2016. The Company or the lenders may request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced. The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the Borrower’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1.0% to 2.0% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2.0% to 3.0% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0% ) plus 1% . For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments. The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including (i) a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of (a) if the Company has unused availability greater than or equal to 75% of the aggregate commitments of the Lenders at all times during the consecutive three month period prior to and including the date of each fiscal quarter end, the maximum ratio of total debt to EBITDAX is 5.0 to 1.0 as of the last day of the fiscal quarter ending March 31, 2016, 5.5 to 1.0 as of the last day of the fiscal quarter ending June 30, 2016 and 5.75 to 1.0 as of the last day of the fiscal quarters ending September 30, 2016 and December 31, 2016, with in each case the amount of total debt for such quarterly period reduced by the amount of unencumbered and unrestricted cash of the Company and cash subject to an account control agreement, (b) if the Company has unused availability of less than 75% of the aggregate commitments of the Lenders at any time during the consecutive three month period prior to and including the date of calculating the ratio, the maximum ratio of total debt to EBITDAX will be 5.75 to 1.00 as of the last day of the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016 and 5.25 to 1.00 as of the last day of the fiscal quarter ending December 31, 2016, and (c) 5.00 to 1.00 as of the last day of any fiscal quarter ending on or after March 31, 2017 and (ii) a minimum ratio of EBITDAX to total cash interest expense of 1.0 to 1.0 , all as defined in the Credit Agreement. In addition, the Credit Agreement permits a sale of the majority of the Company’s remaining oil and gas assets in Oklahoma, provided that such sale is consummated on or prior to March 31, 2016, all of the consideration received in such sale is cash, and the borrowing base will be reduced by $10 million upon the consummation of such sale. The Credit Agreement currently prohibits the Company from declaring and paying dividends on its Series B Preferred Stock. The Credit 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, 2015 , the Company was in compliance with all such covenants contained in the Credit Agreement.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
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 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. During 2013 , 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 $92,000 and $269,000 , respectively, and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $200 . 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, 2015 , the Company’s joint interest billing receivable included approximately $10,000 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, 2015 . Periodically, the Company charters private aircraft for business purposes. During 2014 , the Company paid approximately $18,200 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 2015 and 2013. 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, 2015
Ceiling Test [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, 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 $2.42 per Mcf of natural gas, $50.29 per barrel of oil and $2.21 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 $266.6 million during 2015 . No such write-down occurred during 2014 or 2013 . The Company’s cash flow hedges in place at December 31, 2015 decreased the ceiling test write-down by approximately $1.1 million .

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Other Comprehensive Income	Other Comprehensive Income The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2014 (in thousands): Gains and Losses on Cash Flow Hedges Change in Valuation Allowance Total Balance as of December 31, 2013 $ (688 ) $ (408 ) $ (1,096 ) Other comprehensive income before reclassifications: Change in fair value of derivatives 6,683 6,683 Income tax effect (2,487 ) 408 (2,079 ) Net of tax 4,196 408 4,604 Amounts reclassified from accumulated other comprehensive income: Oil and gas sales 3,044 3,044 Income tax effect (1,132 ) — (1,132 ) Net of tax 1,912 — 1,912 Net other comprehensive income 6,108 408 6,516 Balance as of December 31, 2014 $ 5,420 $ — $ 5,420 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

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
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 cumulative three -year 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 $143.5 million as of December 31, 2015 . An analysis of the Company’s deferred taxes follows (amounts in thousands): December 31, 2015 2014 2013 Net operating loss carryforwards $ 24,014 $ 17,705 $ 21,810 Percentage depletion carryforward 10,592 10,206 8,645 Alternative minimum tax credits 784 784 784 Contributions carryforward and other 266 241 189 Temporary differences: Oil and gas properties 90,291 (15,439 ) (7,248 ) Asset retirement obligation 15,831 20,449 18,056 Derivatives (561 ) (3,211 ) 408 Share-based compensation 2,291 2,560 2,887 Valuation allowance (143,508 ) (33,295 ) (45,531 ) Deferred taxes $ — $ — $ — At December 31, 2015 , the Company had approximately $77.1 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 $8.7 million of such carryforwards would expire in 2025 and the remainder would expire by the year 2034 . The Company has available for tax reporting purposes $30.3 million in statutory depletion deductions that may be carried forward indefinitely. Income tax expense (benefit) for each of the years ended December 31, 2015 , 2014 and 2013 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, 2015 2014 2013 Amount computed using the statutory rate $ (102,257 ) $ 9,887 $ 5,041 Increase (reduction) in taxes resulting from: State & local taxes (6,477 ) 904 317 Percentage depletion carryforward (404 ) (1,564 ) (1,323 ) Non-deductible stock option expense (1) 90 213 115 Share-based compensation (2) 1,317 90 780 Other 113 (643 ) 1,132 Change in valuation allowance 110,244 (11,828 ) (5,742 ) Income tax expense (benefit) $ 2,626 $ (2,941 ) $ 320 (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, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The Company is a party to ongoing litigation in the normal course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management believes that the effect on its financial condition, results of operations and cash flows, if any, will not be material. 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, 2015 under these operating leases are as follows (in thousands): 2016 $ 1,419 2017 1,310 2018 452 2019 422 2020 417 Thereafter 1,225 $ 5,245 Total rent expense under operating leases was approximately $1.7 million , $1.6 million and $1.4 million in 2015 , 2014 and 2013 , respectively.

Supplementary Information on Oi

Supplementary Information on Oil and Gas Operations—Unaudited	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Acquisition costs: Proved (1) $ 2,287 $ 3,064 $ 177,880 Unproved (1) 2,550 39,164 35,008 Exploration costs: Proved 29,322 67,297 34,344 Unproved 7,677 13,515 20,112 Development costs 9,888 55,722 41,328 Capitalized general and administrative and interest costs 12,881 22,121 19,911 Total costs incurred $ 64,605 $ 200,883 $ 328,583 For the Year-Ended December 31, 2015 2014 2013 Accumulated depreciation, depletion and amortization (DD&A) Balance, beginning of year $ (1,648,060 ) $ (1,553,044 ) $ (1,472,244 ) Provision for DD&A (62,138 ) (86,406 ) (69,357 ) Ceiling test writedown (266,562 ) — — Sale of proved properties and other (2) (3) 819,305 (8,610 ) (11,443 ) Balance, end of year $ (1,157,455 ) $ (1,648,060 ) $ (1,553,044 ) DD&A per Mcfe $ 1.82 $ 1.99 $ 1.82 (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. During 2013 , the Company closed on the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million (see Note 2). Additionally, the Company acquired 13,500 net unevaluated acres in Oklahoma targeting the Woodford Shale in 2013 . (2) During 2015 , the Company sold its Woodford and Mississippian Lime assets for an aggregate cash purchase price of $274.1 million (see Note 2). (3) 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 . During 2013 , the Company sold 50% of its saltwater disposal systems and related surface assets in the Woodford for net proceeds of approximately $10.4 million and its non-operated Wyoming assets for a cash purchase price of $1.0 million . At December 31, 2015 and 2014 , unevaluated oil and gas properties totaled $12.5 million and $109.1 million , respectively, and were not subject to depletion. Unevaluated costs at December 31, 2015 included $0.2 million of costs related to two exploratory wells in progress at year-end. These costs are expected to be transferred to evaluated oil and gas properties during 2016 upon the completion of drilling. At December 31, 2014 , unevaluated costs included $16.8 million related to 16 exploratory wells in progress. All of these costs were transferred to evaluated oil and gas properties during 2015 . The Company capitalized $4.7 million , $10.0 million and $6.6 million of interest during 2015 , 2014 and 2013 , respectively. Of the total unevaluated oil and gas property costs of $12.5 million at December 31, 2015 , $(3.1) million , or (25)% , was incurred in 2015 , $3.6 million , or 29% , was incurred in 2014 and $12.1 million , or 96% , was incurred in prior years. The Company expects that the majority of the unevaluated costs at December 31, 2015 will be evaluated within the next 3 years, including $0.2 million that the Company expects to be evaluated during 2016 . Oil and Gas Reserve Information The Company’s net proved oil and gas reserves at December 31, 2015 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-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, 2012 1,635 24,366 188,264 222,441 Revisions of previous estimates (156 ) 804 38,383 38,247 Extensions, discoveries and other additions 434 6,099 30,429 39,132 Purchase of producing properties 1,833 1,915 22,274 35,187 Sale of reserves in place (34 ) — (15 ) (218 ) Production (681 ) (4,754 ) (29,226 ) (38,066 ) 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 Proved developed reserves As of December 31, 2013 2,709 23,173 163,728 203,152 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 Proved undeveloped reserves As of December 31, 2013 322 5,257 86,381 93,571 As of December 31, 2014 348 30,914 126,458 159,460 As of December 31, 2015 257 19,034 53,811 74,389 Year Ended December 31, 2015 During 2015 , the Company’s estimated proved reserves decrease d by 55% . Sales of reserves in place was primarily due to the divestiture of the majority of the Company's Woodford 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. Year Ended December 31, 2013 Extensions, discoveries and other additions were primarily due to the success of the Company's Oklahoma, Texas and Gulf Coast drilling programs. The Company added approximately 23 Bcfe of proved reserves in Oklahoma, 5 Bcfe in the Gulf Coast and 10 Bcfe in Texas. Revisions of previous estimates were primarily a result of the increase in the historical 12-month average price per Mcf of natural gas used to calculate estimated proved reserves, which was $3.11 per Mcf at December 31, 2013 as compared to $2.20 per Mcf at December 31, 2012. The 35 Bcfe added through purchase of producing properties relates to the Company's Gulf of Mexico Acquisition (See Note 2). 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, 2015 2014 2013 Future cash flows $ 487,834 $ 1,711,404 $ 1,243,627 Future production costs (171,678 ) (372,690 ) (295,666 ) Future development costs (116,591 ) (244,784 ) (185,188 ) Future income taxes — (121,192 ) (37,404 ) Future net cash flows 199,565 972,738 725,369 10% annual discount (71,880 ) (424,176 ) (274,189 ) Standardized measure of discounted future net cash flows $ 127,685 $ 548,562 $ 451,180 Changes in Standardized Measure Year Ended December 31, 2015 2014 2013 Standardized measure at beginning of year $ 548,562 $ 451,180 $ 230,823 Sales and transfers of oil and gas produced, net of production costs (55,849 ) (173,540 ) (134,184 ) Changes in price, net of future production costs (267,710 ) 37,204 55,601 Extensions and discoveries, net of future production and development costs 70,928 237,290 70,181 Changes in estimated future development costs, net of development costs incurred during this period 31,007 11,094 (25,389 ) Revisions of quantity estimates (14,427 ) 25,591 58,508 Accretion of discount 60,071 47,130 23,776 Net change in income taxes 52,149 (32,034 ) (13,182 ) Purchase of reserves in place — — 191,964 Sale of reserves in place (194,454 ) (7,240 ) (411 ) Changes in production rates (timing) and other (102,592 ) (48,113 ) (6,507 ) Net increase (decrease) in standardized measure (420,877 ) 97,382 220,357 Standardized measure at end of year $ 127,685 $ 548,562 $ 451,180 The historical twelve-month average prices of oil, gas and natural gas liquids used in determining standardized measure were: 2015 2014 2013 Oil, $/Bbl $50.29 $96.45 $106.19 Ngls, $/Mcfe 2.24 4.11 5.10 Natural Gas, $/Mcf 2.41 3.80 3.11

Summarized Quarterly Financial

Summarized Quarterly Financial Information—Unaudited	12 Months Ended
	Dec. 31, 2015
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 2015: Revenues $ 33,451 $ 32,550 $ 26,872 $ 23,096 Loss from operations (1) (121,887 ) (57,796 ) (50,617 ) (61,864 ) Loss available to common stockholders (1) (122,240 ) (61,083 ) (51,910 ) (64,696 ) Earnings per share: Basic $ (1.89 ) $ (0.94 ) $ (0.80 ) $ (0.98 ) Diluted $ (1.89 ) $ (0.94 ) $ (0.80 ) $ (0.98 ) 2014: Revenues $ 59,966 $ 60,581 $ 56,486 $ 47,988 Income from operations 11,323 10,879 5,569 478 Income available to common stockholders 10,043 9,592 4,671 1,745 Earnings per share: Basic $ 0.15 $ 0.15 $ 0.07 $ 0.02 Diluted $ 0.15 $ 0.15 $ 0.07 $ 0.02 (1) Loss from operations and net 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 net 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 S26

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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.
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 first of the month average twelve-month 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 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. During 2012, a field office servicing the Company's Oklahoma assets was built and is being depreciated over 39 years.
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 which 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 realizabilty 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.
Certain Concentrations	Concentrations The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary.
Derivatives Instruments	Derivative Instruments Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is effective. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the statement of operations as derivative income (expense). The Company does not offset fair value amounts recognized for derivative instruments. The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2015 , the Company’s derivative instruments were designated as effective cash flow hedges. See Note 8 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. Early application is not permitted. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. The Company 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 April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs", which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt liability rather than as an asset. Additionally, in August 2015, the FASB issued ASU No. 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which was issued to clarify the guidance with respect to the presentation of debt issuance costs related to line-of-credit arrangements. ASU 2015-15 clarifies that the SEC staff would not object to an entity deferring and presenting such debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company has elected to early adopt this standard effective December 31, 2015.

Organization and Summary of S27

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Laclede Energy 21% 24% 14% Shell Trading Co. 18% 30% 35% Unimark, LLC 17% 14% 14% BG Group 10% (a) (a) (a) Less than 10 percent

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the acquisition date fair values of the net assets acquired (in thousands): Oil and gas properties $ 192,067 Unevaluated oil and gas properties 12,033 Asset retirement obligations (15,319 ) Net assets acquired $ 188,781
Summary pro forma statement of operations	The following unaudited summary pro forma financial information for the twelve month periods ended December 31, 2013 has been prepared to give effect to the Gulf of Mexico Acquisition as if it had occurred on January 1, 2012. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2012 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following unaudited pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors. Amounts are presented in thousands, except per share amounts. Twelve Months Ended December 31, 2013 Revenues $ 215,666 Income from Operations 19,858 Net Income available to common stockholders 14,399 Basic Earnings per Share $ 0.22 Diluted Earnings per Share $ 0.22

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 Loss(Numerator) Shares Per BASIC EPS Net loss available to common stockholders $ (299,929 ) 65,022 $ (4.61 ) Stock options — — Attributable to participating securities — — DILUTED EPS $ (299,929 ) 65,022 $ (4.61 ) For the Year Ended December 31, 2014 Income(Numerator) Shares Per Net income available to common stockholders $ 26,051 64,204 Attributable to participating securities (855 ) — BASIC EPS $ 25,196 64,204 $ 0.39 Net income available to common stockholders $ 26,051 64,204 Effect of dilutive securities: Stock options — 21 Attributable to participating securities (854 ) — DILUTED EPS $ 25,197 64,225 $ 0.39 For the Year Ended December 31, 2013 Income(Numerator) Shares Per Net income available to common stockholders $ 8,943 63,054 Attributable to participating securities (257 ) — BASIC EPS $ 8,686 63,054 $ 0.14 Net income available to common stockholders $ 8,943 63,054 Effect of dilutive securities: Stock options — 154 Attributable to participating securities (256 ) — DILUTED EPS $ 8,687 63,208 $ 0.14

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 , 2014 and 2013 is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Stock options: Incentive Stock Options (share settled) $ 243 $ 573 $ 310 Non-Qualified Stock Options (share settled) 71 171 222 Restricted stock (share settled) 4,303 4,504 3,684 Cash settled stock units (439 ) 3,094 1,611 Share-based compensation $ 4,178 $ 8,342 $ 5,827
Schedule of stock option valuation assumptions	The following table outlines the assumptions used in computing the fair value of stock options granted during 2014 and 2013 : Years Ended December 31, 2014 2013 Dividend yield —% —% Expected volatility 79.4% - 80.0% 79.6% - 79.8% Risk-free rate 1.81% - 2.015% 0.9% - 1.815% Expected term 6 years 6 years Forfeiture rate 5.0% 5.0% Stock options granted (1) 69,434 395,642 Wgtd. avg. grant date fair value per share $2.84 $2.91 Fair value of grants (1) $197,000 $1,150,000 (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, 2015 : Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Remaining Life Aggregate Intrinsic Value (000’s) Outstanding at beginning of year 1,517,704 $ 6.05 Granted — — Expired/cancelled/forfeited (155,680 ) 5.70 Exercised — — Outstanding at end of year 1,362,024 6.09 5.6 years $ — Options exercisable at end of year 1,217,486 $ 6.33 4.4 years $ — Options expected to vest 137,311 4.13 7.9 years $ —
Schedule of stock option plans, by exercise price range	The following table summarizes information regarding stock options outstanding at December 31, 2015 : Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg. Exercise Outstanding Remaining Exercise Exercisable Exercise Price 12/31/2015 Contractual Life Price 12/31/2015 Price $2.24—$4.48 386,908 7.8 years $4.13 251,701 $4.16 $4.49—$6.72 220,487 5.7 years $5.46 211,156 $5.48 $6.73—$8.96 744,629 4.5 years $7.25 744,629 $7.25 $8.97—$11.20 10,000 0.1 years $9.99 10,000 $9.99 1,362,024 5.6 years $6.09 1,217,486 $6.33
Schedule of restricted stock units activity	The following table details restricted stock activity during the year ended December 31, 2015 : Number of Shares Wgtd. Avg. Fair Value per Share Outstanding at beginning of year 2,428,202 $ 4.37 Granted 54,717 1.27 Cancelled/forfeited (187,730 ) 3.88 Lapse of restrictions (1,110,013 ) 4.27 Outstanding at December 31, 2015 1,185,176 $ 3.81 As of December 31, 2015 , the Company had a liability for RSUs and MRSUs outstanding in the amount of $0.2 million based upon the closing stock price at December 31, 2015 . The following table details MRSU and RSU activity during the year ended December 31, 2015 : MRSU RSU Total Outstanding at beginning of year 243,067 1,379,261 1,622,328 Granted — 182,505 182,505 Expired/Cancelled/Forfeited (139,784 ) (120,438 ) (260,222 ) Vested/Paid — (687,704 ) (687,704 ) Outstanding at December 31, 2015 103,283 753,624 856,907

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Asset retirement obligation, beginning of period $ 54,970 $ 48,536 Liabilities incurred 466 756 Liabilities settled (5,002 ) (3,623 ) Accretion expense 3,259 2,958 Revisions in estimated cash flows (11,137 ) 6,343 Asset retirement obligation, end of period 42,556 54,970 Less: current portion of asset retirement obligation (6,015 ) (2,756 ) Long-term asset retirement obligation $ 36,541 $ 52,214

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Oil and gas contracts	As of December 31, 2015 , the Company had entered into the following gas hedge contract: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: January 2016 - June 2016 Swap 10,000 Mmbtu $3.22 At December 31, 2015 , the Company had recognized an asset of approximately $1.5 million related to the estimated fair value of this derivative contract. Based on estimated future commodity prices as of December 31, 2015 , the Company would realize a $0.9 million gain, net of taxes, during the next 12 months. This gain is expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts. During January 2016, the Company entered into the following additional derivative contract accounted for as a cash flow hedge: Production Period Instrument Type Daily Volumes Weighted Average Price Natural Gas: July 2016 - December 2016 Swap 5,000 Mmbtu $2.50
Effect of cash flow hedges on the consolidated balance sheet	Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2015 and December 31, 2014 : Commodity Derivatives Period Balance Sheet Fair Value December 31, 2015 Derivative asset $ 1,508 December 31, 2014 Derivative asset $ 8,631
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, 2015 , 2014 and 2013 : Instrument Amount of Gain (Loss) Location of Amount of Gain (Loss) Reclassified into 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 ) Commodity Derivatives at December 31, 2013 $ (999 ) Oil and gas sales $ 927
Effect of non-designated derivative instruments	Effect of Non-designated Derivative Instrument on the Consolidated Statement of Operations for the year ended December 31, 2013 : Instrument Amount of Gain Commodity Derivatives at December 31, 2013 $ 233

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis as of December 31, 2015 and December 31, 2014 (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, 2015 $ — $ 1,508 $ — At December 31, 2014 $ — $ 8,631 $ —

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2014 (in thousands): Gains and Losses on Cash Flow Hedges Change in Valuation Allowance Total Balance as of December 31, 2013 $ (688 ) $ (408 ) $ (1,096 ) Other comprehensive income before reclassifications: Change in fair value of derivatives 6,683 6,683 Income tax effect (2,487 ) 408 (2,079 ) Net of tax 4,196 408 4,604 Amounts reclassified from accumulated other comprehensive income: Oil and gas sales 3,044 3,044 Income tax effect (1,132 ) — (1,132 ) Net of tax 1,912 — 1,912 Net other comprehensive income 6,108 408 6,516 Balance as of December 31, 2014 $ 5,420 $ — $ 5,420 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

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Deferred Taxes	An analysis of the Company’s deferred taxes follows (amounts in thousands): December 31, 2015 2014 2013 Net operating loss carryforwards $ 24,014 $ 17,705 $ 21,810 Percentage depletion carryforward 10,592 10,206 8,645 Alternative minimum tax credits 784 784 784 Contributions carryforward and other 266 241 189 Temporary differences: Oil and gas properties 90,291 (15,439 ) (7,248 ) Asset retirement obligation 15,831 20,449 18,056 Derivatives (561 ) (3,211 ) 408 Share-based compensation 2,291 2,560 2,887 Valuation allowance (143,508 ) (33,295 ) (45,531 ) Deferred taxes $ — $ — $ —
Income Tax Reconciliation	Income tax expense (benefit) for each of the years ended December 31, 2015 , 2014 and 2013 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, 2015 2014 2013 Amount computed using the statutory rate $ (102,257 ) $ 9,887 $ 5,041 Increase (reduction) in taxes resulting from: State & local taxes (6,477 ) 904 317 Percentage depletion carryforward (404 ) (1,564 ) (1,323 ) Non-deductible stock option expense (1) 90 213 115 Share-based compensation (2) 1,317 90 780 Other 113 (643 ) 1,132 Change in valuation allowance 110,244 (11,828 ) (5,742 ) Income tax expense (benefit) $ 2,626 $ (2,941 ) $ 320 (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, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Lease Commitments	Future minimum lease commitments as of December 31, 2015 under these operating leases are as follows (in thousands): 2016 $ 1,419 2017 1,310 2018 452 2019 422 2020 417 Thereafter 1,225 $ 5,245

Supplementary Information on 37

Supplementary Information on Oil and Gas Operations—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Acquisition costs: Proved (1) $ 2,287 $ 3,064 $ 177,880 Unproved (1) 2,550 39,164 35,008 Exploration costs: Proved 29,322 67,297 34,344 Unproved 7,677 13,515 20,112 Development costs 9,888 55,722 41,328 Capitalized general and administrative and interest costs 12,881 22,121 19,911 Total costs incurred $ 64,605 $ 200,883 $ 328,583
Rollforward of accumulated depreciation, depletion and amortization of oil and gas producing activities	For the Year-Ended December 31, 2015 2014 2013 Accumulated depreciation, depletion and amortization (DD&A) Balance, beginning of year $ (1,648,060 ) $ (1,553,044 ) $ (1,472,244 ) Provision for DD&A (62,138 ) (86,406 ) (69,357 ) Ceiling test writedown (266,562 ) — — Sale of proved properties and other (2) (3) 819,305 (8,610 ) (11,443 ) Balance, end of year $ (1,157,455 ) $ (1,648,060 ) $ (1,553,044 ) DD&A per Mcfe $ 1.82 $ 1.99 $ 1.82 (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. During 2013 , the Company closed on the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million (see Note 2). Additionally, the Company acquired 13,500 net unevaluated acres in Oklahoma targeting the Woodford Shale in 2013 . (2) During 2015 , the Company sold its Woodford and Mississippian Lime assets for an aggregate cash purchase price of $274.1 million (see Note 2). (3) 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 . During 2013 , the Company sold 50% of its saltwater disposal systems and related surface assets in the Woodford for net proceeds of approximately $10.4 million and its non-operated Wyoming assets for a cash purchase price of $1.0 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, 2012 1,635 24,366 188,264 222,441 Revisions of previous estimates (156 ) 804 38,383 38,247 Extensions, discoveries and other additions 434 6,099 30,429 39,132 Purchase of producing properties 1,833 1,915 22,274 35,187 Sale of reserves in place (34 ) — (15 ) (218 ) Production (681 ) (4,754 ) (29,226 ) (38,066 ) 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 Proved developed reserves As of December 31, 2013 2,709 23,173 163,728 203,152 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 Proved undeveloped reserves As of December 31, 2013 322 5,257 86,381 93,571 As of December 31, 2014 348 30,914 126,458 159,460 As of December 31, 2015 257 19,034 53,811 74,389
Standardized measure of discounted future cash flows	Standardized Measure December 31, 2015 2014 2013 Future cash flows $ 487,834 $ 1,711,404 $ 1,243,627 Future production costs (171,678 ) (372,690 ) (295,666 ) Future development costs (116,591 ) (244,784 ) (185,188 ) Future income taxes — (121,192 ) (37,404 ) Future net cash flows 199,565 972,738 725,369 10% annual discount (71,880 ) (424,176 ) (274,189 ) Standardized measure of discounted future net cash flows $ 127,685 $ 548,562 $ 451,180
Schedule of changes in standardized measure of discounted future net cash flows	Changes in Standardized Measure Year Ended December 31, 2015 2014 2013 Standardized measure at beginning of year $ 548,562 $ 451,180 $ 230,823 Sales and transfers of oil and gas produced, net of production costs (55,849 ) (173,540 ) (134,184 ) Changes in price, net of future production costs (267,710 ) 37,204 55,601 Extensions and discoveries, net of future production and development costs 70,928 237,290 70,181 Changes in estimated future development costs, net of development costs incurred during this period 31,007 11,094 (25,389 ) Revisions of quantity estimates (14,427 ) 25,591 58,508 Accretion of discount 60,071 47,130 23,776 Net change in income taxes 52,149 (32,034 ) (13,182 ) Purchase of reserves in place — — 191,964 Sale of reserves in place (194,454 ) (7,240 ) (411 ) Changes in production rates (timing) and other (102,592 ) (48,113 ) (6,507 ) Net increase (decrease) in standardized measure (420,877 ) 97,382 220,357 Standardized measure at end of year $ 127,685 $ 548,562 $ 451,180
Average sales price and average production costs	The historical twelve-month average prices of oil, gas and natural gas liquids used in determining standardized measure were: 2015 2014 2013 Oil, $/Bbl $50.29 $96.45 $106.19 Ngls, $/Mcfe 2.24 4.11 5.10 Natural Gas, $/Mcf 2.41 3.80 3.11

Summarized Quarterly Financia38

Summarized Quarterly Financial Information—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2015
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 2015: Revenues $ 33,451 $ 32,550 $ 26,872 $ 23,096 Loss from operations (1) (121,887 ) (57,796 ) (50,617 ) (61,864 ) Loss available to common stockholders (1) (122,240 ) (61,083 ) (51,910 ) (64,696 ) Earnings per share: Basic $ (1.89 ) $ (0.94 ) $ (0.80 ) $ (0.98 ) Diluted $ (1.89 ) $ (0.94 ) $ (0.80 ) $ (0.98 ) 2014: Revenues $ 59,966 $ 60,581 $ 56,486 $ 47,988 Income from operations 11,323 10,879 5,569 478 Income available to common stockholders 10,043 9,592 4,671 1,745 Earnings per share: Basic $ 0.15 $ 0.15 $ 0.07 $ 0.02 Diluted $ 0.15 $ 0.15 $ 0.07 $ 0.02 (1) Loss from operations and net 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 net 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 S39

Organization and Summary of Significant Accounting Policies - PPE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Allowance for doubtful accounts		$ 0
Furniture and Fixtures | Minimum
Property, Plant and Equipment [Line Items]
Useful life (in years)	3 years
Furniture and Fixtures | Maximum
Property, Plant and Equipment [Line Items]
Useful life (in years)	8 years
Oklahoma | Building
Property, Plant and Equipment [Line Items]
Useful life (in years)	39 years

Organization and Summary of S40

Organization and Summary of Significant Accounting Policies Organization and Summary of Significant Accounting Policies - Revenues (Details) - Oil and Gas Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Laclede Energy
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	18.00%	30.00%	35.00%
Shell Trading Co.
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	21.00%	24.00%	14.00%
Unimark, LLC
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	17.00%	14.00%	14.00%
BG Group
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	10.00%

Organization and Summary of S41

Organization and Summary of Significant Accounting Policies - Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jul. 03, 2013
Derivatives, Fair Value [Line Items]
Deferred finance costs	$ 1.4	$ 0.7
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	$ 17.1	$ (3)	$ 0.9
Senior Notes | 10% Senior Notes
Derivatives, Fair Value [Line Items]
Stated interest rate (as a percent)	10.00%	10.00%		10.00%
Deferred finance costs	$ 3	$ 4.8

Acquisitions and Divestitures42

Acquisitions and Divestitures (Details) a in Thousands	Jul. 03, 2013USD ($)wellplatform	Feb. 29, 2016USD ($)	Jun. 30, 2014USD ($)ami²	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)a	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Payments of financing costs				$ 1,094,000	$ 253,000	$ 320,000
Accrued acquisition costs				$ 4,409,000	17,690,000
10% Senior Notes
Business Acquisition [Line Items]
Interest rate of Senior Notes (as a percent)				10.00%
Payments of financing costs	$ 5,000,000
Acquisition-related costs	$ 4,000,000
Gulf of Mexico Acquisition
Business Acquisition [Line Items]
Number of wells acquired | well	16
Number of platforms purchased | platform	7
Gulf of Mexico Acquisition | 10% Senior Notes
Business Acquisition [Line Items]
Principal amount	$ 200,000,000
Interest rate of Senior Notes (as a percent)				10.00%
Gulf of Mexico Acquisition | General and Administrative Expense | Bridge Loan
Business Acquisition [Line Items]
Acquisition-related costs	$ 2,600,000
10% Senior Notes | Gulf of Mexico Acquisition
Business Acquisition [Line Items]
Purchase price						$ 188,800,000
Louisiana | Fleetwood Joint Venture
Business Acquisition [Line Items]
Purchase price			$ 10,000,000
Aggregate purchase price			$ 24,000,000		$ 24,000,000
Working interest (as a percent)			37.00%
Number of acres acquired | a			30		30
Number of square miles | mi²			200
Cash funding for future drilling			$ 14,000,000
Subsequent Event | Louisiana | Fleetwood Joint Venture
Business Acquisition [Line Items]
Payment to settle liability (accrued acquisition costs)		$ 4,400,000

Acquisitions and Divestitures43

Acquisitions and Divestitures (Schedule of Assets Acquired and Liabilities Assumed) (Details) - Gulf of Mexico Acquisition $ in Thousands	Jul. 03, 2013USD ($)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Oil and gas properties	$ 192,067
Unevaluated oil and gas properties	12,033
Asset retirement obligations	(15,319)
Net assets acquired	$ 188,781

Acquisitions and Divestitures44

Acquisitions and Divestitures (Pro Forma) (Details) - Gulf of Mexico Acquisition $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)$ / shares
Business Acquisition [Line Items]
Revenues	$ 215,666
Income from Operations	19,858
Net Income available to common stockholders	$ 14,399
Basic Earnings (loss) per Share (in dollars per share) | $ / shares	$ 0.22
Diluted Earnings (loss) per Share (in dollars per share) | $ / shares	$ 0.22

Acquisitions and Divestitures -

Acquisitions and Divestitures - Divestitures (Woodford and Mississippian Lime Interests) (Details) $ in Thousands, Mcfe in Millions	Jun. 04, 2015USD ($)term	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)Mcfe	Dec. 31, 2013USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of assets		$ 21,500	$ 21,937	$ 0	$ 0
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
Number of renewal terms for contract operator | term	2
Contract operator term for sold assets	1 year
Proved reserves | Mcfe				227.2
Estimated proved reserves attributable to Sold Assets (percent of total)				57.00%
Gain on sale of assets			$ 23,200
Woodford And Mississippian Lime | Current Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other receivable	$ 13,900

Subsequent Event (Details)

Subsequent Event (Details) - USD ($)	Feb. 17, 2016	Jan. 14, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 03, 2013
10% Senior Notes | Senior Notes
Subsequent Event [Line Items]
Long-term debt			$ 300,000,000
Stated interest rate (as a percent)			10.00%	10.00%	10.00%
10% Senior Notes | Senior Notes | Subsequent Event
Subsequent Event [Line Items]
Long-term debt	$ 135,600,000
Private Exchange Offer and Consent Solicitation | Subsequent Event
Subsequent Event [Line Items]
Maximum cash consideration to be paid		$ 75,000,000
Shares to be issued		$ 6,000,000
Original debt, amount	$ 214,400,000
Original debt, percent of total	61.00%
Repayments of debt	$ 53,600,000
Private Exchange Offer and Consent Solicitation | Second LIen Senior Secured Notes due 2021 | Senior Notes | Subsequent Event
Subsequent Event [Line Items]
Stated interest rate (as a percent)		10.00%
Aggregate principal to be issued		$ 202,500,000
Converted instrument, amount	$ 144,700,000
Common Stock | Private Exchange Offer and Consent Solicitation | Subsequent Event
Subsequent Event [Line Items]
Shares issued	4,287,580

Convertible Preferred Stock (De

Convertible Preferred Stock (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Convertible Preferred Stock (Textual) [Abstract]
Preferred stock, outstanding shares	1,495,000	1,495,000
Series B cumulative convertible perpetual preferred stock interest rate	6.875%
Terms of applicable conversion terms	Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into 3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share of common stock, subject to 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.
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)	3.4433
Initial conversion price of common stock (in usd per share)	$ 14.52
Applicable settlement terms	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.
Trading day averaging period for determining conversion value	20 days
Conversion rate numerator for Preferred Stock	$ 50

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
A reconciliation between basic and diluted earnings per share computations
Net income (loss) available to common stockholders	$ (64,696)	$ (51,910)	$ (61,083)	$ (122,240)	$ 1,745	$ 4,671	$ 9,592	$ 10,043	$ (299,929)	$ 26,051	$ 8,943
Net loss available to common stockholders (in shares)									65,022	64,204	63,054
Net loss available to common stockholders (in usd per share)	$ (0.98)	$ (0.80)	$ (0.94)	$ (1.89)	$ 0.02	$ 0.07	$ 0.15	$ 0.15	$ (4.61)	$ 0.39	$ 0.14
Stock options, effect of dilutive securities									$ 0
Stock options, effect of dilutive securities, (in shares)										21	154
Attributable to participating securities									$ 0	$ (854)	$ (256)
Restricted stock, effect of dilutive securities (in shares)									0	0	0
Attributable to participating securities, basic										$ (855)	$ (257)
Net income or loss available to common stockholders, Loss (excluding income attributable to participating securities)										25,196	8,686
DILUTED EPS, Loss									$ (299,929)	$ 25,197	$ 8,687
DILUTED EPS (in shares)									65,022	64,225	63,208
DILUTED EPS, per share amount (in usd per share)	$ (0.98)	$ (0.80)	$ (0.94)	$ (1.89)	$ 0.02	$ 0.07	$ 0.15	$ 0.15	$ (4.61)	$ 0.39	$ 0.14

Earnings Per Share (Details Tex

Earnings Per Share (Details Textual) - shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Convertible preferred stock
Earnings Per Share (Textual) [Abstract]
Common stock issuable on conversion (in shares)	5.1	5.1	5.1
Stock Options
Earnings Per Share (Textual) [Abstract]
Common stock issuable on conversion (in shares)	0.3	1	1.2

Share-Based Compensation - Shar

Share-Based Compensation - Share based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of share-based compensation
Share based compensation	$ 4,178	$ 8,342	$ 5,827
Incentive Stock Options (share settled)
Summary of share-based compensation
Share based compensation	243	573	310
Non-Qualified Stock Options (share settled)
Summary of share-based compensation
Share based compensation	71	171	222
Restricted stock (share settled)
Summary of share-based compensation
Share based compensation	4,303	4,504	3,684
Cash settled stock units
Summary of share-based compensation
Share based compensation	$ (439)	$ 3,094	$ 1,611

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2014shares	Dec. 31, 2015USD ($)companyshares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Tax benefit from compensation expense | $		$ 1.5	$ 2.3	$ 1.8
Total compensation cost not yet recognized | $		$ 2.3
Period for recognition (in years)		2 years
Fair value of stock options that vested during period | $		$ 0.8	$ 1	$ 0.8
Granted (in shares) | shares		182,505
Restricted stock (share settled)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period until vesting (in years)		1 year
Forfeiture rate (as a percent)		5.00%
Granted (in shares) | shares		54,717
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period (in years)		3 years
Award expiration period (in years)		10 years
Forfeiture rate (as a percent)			5.00%	5.00%
Exercise price percent of fair value at grant date		100.00%
Cash settled stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares		182,505
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	243,067	0
Evaluation period (in days)		20 days
Number of peer group companies | company		12
Prior to 2011 | Restricted stock (share settled)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period (in years)		5 years
Annual vesting percentage		25.00%
Prior to 2013 | Restricted stock (share settled)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period (in years)		3 years
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%
Oil and Gas Properties
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation costs capitalized in period | $			$ 1.5	$ 0.8

Share-Based Compensation - Fair

Share-Based Compensation - Fair Value Assumption (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Stock options granted (shares)	0
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Dividend yield (as a percent)		0.00%	0.00%
Expected volatility, minimum (as a percent)		79.40%	79.60%
Expected volatility, maximum (as a percent)		80.00%	79.80%
Risk-free rate, minimum (as a percent)		1.81%	0.90%
Risk-free rate, maximum (as a percent)		2.015%	1.815%
Expected term (in years)		6 years	6 years
Forfeiture rate (as a percent)		5.00%	5.00%
Stock options granted (shares)		69,434	395,642
Weighted average grant date fair value (usd per share)		$ 2.84	$ 2.91
Fair value of grants		$ 197	$ 1,150

Share-Based Compensation - Acti

Share-Based Compensation - Activity (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
Number of Options (in shares)
Outstanding at beginning of year | shares	1,517,704
Granted | shares	0
Expired/cancelled/forfeited | shares	(155,680)
Exercised | shares	0
Outstanding at end of year | shares	1,362,024
Wgtd. Avg. Exercise Price (in dollars per share)
Outstanding at beginning of year | $ / shares	$ 6.05
Granted | $ / shares	0
Expired/cancelled/forfeited | $ / shares	5.70
Exercised | $ / shares	0
Outstanding at end of year | $ / shares	$ 6.09
Additional Disclosures
Options exercisable at end of year | shares	1,217,486
Options expected to vest | shares	137,311
Options exercisable at end of year (usd per share) | $ / shares	$ 6.33
Options expected to vest (usd per share) | $ / shares	$ 4.13
Outstanding, remaining contractual term (in years)	5 years 7 months 6 days
Exercisable, remaining contractual term (in years)	4 years 5 months 4 days
Vested and expected to vest, remaining contractual term (in years)	7 years 10 months 26 days
Outstanding, intrinsic value | $	$ 0
Exercisable, intrinsic value | $	0
Vested and expected to vest, intrinsic value | $	$ 0

Share-Based Compensation - Exer

Share-Based Compensation - Exercise Prices (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding at end of year (in shares)	1,362,024	1,517,704
Outstanding, remaining contractual term (in years)	5 years 7 months 6 days
Outstanding at end of year	$ 6.09
Options exercisable at end of year	1,217,486
Options exercisable (usd per share)	$ 6.33
$2.24—$4.48
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	2.24
Exercise price range, upper range limit	$ 4.48
Outstanding at end of year (in shares)	386,908
Outstanding, remaining contractual term (in years)	7 years 9 months 17 days
Outstanding at end of year	$ 4.13
Options exercisable at end of year	251,701
Options exercisable (usd per share)	$ 4.16
$4.49—$6.72
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	4.49
Exercise price range, upper range limit	$ 6.72
Outstanding at end of year (in shares)	220,487
Outstanding, remaining contractual term (in years)	5 years 8 months 16 days
Outstanding at end of year	$ 5.46
Options exercisable at end of year	211,156
Options exercisable (usd per share)	$ 5.48
$6.73—$8.96
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	6.73
Exercise price range, upper range limit	$ 8.96
Outstanding at end of year (in shares)	744,629
Outstanding, remaining contractual term (in years)	4 years 5 months 19 days
Outstanding at end of year	$ 7.25
Options exercisable at end of year	744,629
Options exercisable (usd per share)	$ 7.25
$8.97—$11.20
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	8.97
Exercise price range, upper range limit	$ 11.20
Outstanding at end of year (in shares)	10,000
Outstanding, remaining contractual term (in years)	1 month 17 days
Outstanding at end of year	$ 9.99
Options exercisable at end of year	10,000
Options exercisable (usd per share)	$ 9.99

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of Shares (in shares)
Outstanding at beginning of year	1,622,328
Granted	182,505
Cancelled/forfeited	(260,222)
Lapse of restrictions	(687,704)
Outstanding at end of year	856,907	1,622,328
Restricted stock (share settled)
Number of Shares (in shares)
Outstanding at beginning of year	2,428,202
Granted	54,717
Cancelled/forfeited	(187,730)
Lapse of restrictions	(1,110,013)
Outstanding at end of year	1,185,176	2,428,202
Wgtd. Avg. Fair Value per Share (in dollars per share)
Outstanding at beginning of year	$ 4.37
Granted	1.27	$ 4.32	$ 4.18
Cancelled/forfeited	3.88
Lapse of restrictions	4.27
Outstanding at end of year	$ 3.81	$ 4.37
Total value of stock that vested	$ 4.7	$ 5	$ 5.4
Additional Information
Weighted average remaining life (in years)	3 years
Value of restricted stock outstanding	$ 0.6

Share-Based Compensation - Re56

Share-Based Compensation - Restricted Stock Units (Details) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2014shares	Dec. 31, 2015USD ($)companyshares
Number of Shares (in shares)
Outstanding at beginning of year		1,622,328
Granted		182,505
Cancelled/forfeited		(260,222)
Vested/Paid		(687,704)
Outstanding at end of year		856,907
Cash settled stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total value of stock that vested | $		$ 0.7
Liability for RSUs outstanding and expected to vest		200,000
Number of Shares (in shares)
Outstanding at beginning of year		1,379,261
Granted		182,505
Cancelled/forfeited		(120,438)
Vested/Paid		(687,704)
Outstanding at end of year		753,624
Market Based Restricted Stock Units
Number of Shares (in shares)
Granted	243,067	0
Cancelled/forfeited		(139,784)
Vested/Paid		0
Outstanding at end of year		103,283
Evaluation period (in days)		20 days
Number of peer group companies | company		12
Minimum | Market Based Restricted Stock Units
Number of Shares (in shares)
Earning percentage		0.00%
Maximum | Market Based Restricted Stock Units
Number of Shares (in shares)
Earning percentage		200.00%

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 54,970	$ 48,536
Liabilities incurred	466	756
Liabilities settled	(5,002)	(3,623)
Accretion expense	3,259	2,958
Revisions in estimated cash flows	(11,137)	6,343
Asset retirement obligation, end of period	42,556	54,970
Less: current portion of asset retirement obligation	(6,015)	(2,756)
Long-term asset retirement obligation	36,541	$ 52,214
Woodford And Mississippian Lime
Changes to the Company's asset retirement obligation liability
Liabilities settled	$ (1,800)

Derivative Instruments (Details

Derivative Instruments (Details) - Natural Gas: - Swap	12 Months Ended
	Dec. 31, 2015MMBTU$ / shares
January 2016 - June 2016
Oil and gas contracts
Daily Volumes | MMBTU	10,000
Weighted Average Price | $ / shares	$ 3.22
July 2016 - December 2016
Oil and gas contracts
Daily Volumes | MMBTU	5,000
Weighted Average Price | $ / shares	$ 2.50

Derivative Instruments (Detai59

Derivative Instruments (Details 1) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Asset fair value	$ 1,500
Designated as Hedging Instrument | Commodity Derivatives | Current Assets
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Asset fair value	$ 1,508	$ 8,631

Derivative Instruments (Detai60

Derivative Instruments (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Effect of Derivative Instruments on the Consolidated Statement of Operations
Amount of Gain (Loss) Recognized in Other Comprehensive Income	$ (4,473)	$ 6,516	$ (1,617)
Designated as Hedging Instrument
Effect of Derivative Instruments on the Consolidated Statement of Operations
Amount of Gain (Loss) Recognized in Other Comprehensive Income	9,991	6,683	(999)
Designated as Hedging Instrument | Oil and gas sales
Effect of Derivative Instruments on the Consolidated Statement of Operations
Amount of Gain (Loss) Reclassified into Income	$ 17,114	$ (3,044)	$ 927

Derivative Instruments (Detai61

Derivative Instruments (Details 4) $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)
Not Designated as Hedging Instrument
Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations
Amount of Gain Recognized in Derivative Income	$ 233

Derivative Instruments (Detai62

Derivative Instruments (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments (Textual) [Abstract]
Asset fair value	$ 1,500
Realization of gain, net of taxes	900
Gas hedges
Derivative Instruments (Textual) [Abstract]
Net settlement of hedges	15,940	$ (4,237)	$ 1,098
NGL hedges
Derivative Instruments (Textual) [Abstract]
Net settlement of hedges	530	296	61
Crude Oil
Derivative Instruments (Textual) [Abstract]
Net settlement of hedges	$ 644	$ 897	$ (232)

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
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 Fair Value	$ 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 Fair Value	1,508,000	8,631,000
Significant Unobservable Inputs (Level 3)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity Derivatives Fair Value	$ 0	0
10% Senior Notes
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Stated interest rate (as a percent)	10.00%
Estimated fair value of the Notes	$ 350,000,000
10% Senior Notes | Significant Other Observable Inputs (Level 2)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Estimated fair value of the Notes	$ 238,000,000	$ 301,000,000

Long-Term Debt (Details)

Long-Term Debt (Details)	12 Months Ended
	Dec. 31, 2015USD ($)determinationRate	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Feb. 17, 2016USD ($)	Jan. 31, 2016USD ($)	Dec. 31, 2014USD ($)	Jul. 03, 2013USD ($)	Aug. 19, 2010USD ($)
Debt Instrument [Line Items]
Bank debt									$ 75,000,000
At least secured percentage value of oil and gas properties | Rate	90.00%
Maximum
Debt Instrument [Line Items]
Commitment fees on a sliding scale (as a percent)	0.50%
Minimum
Debt Instrument [Line Items]
Commitment fees on a sliding scale (as a percent)	0.375%
Borrower's liquidity (as a percent)	75.00%
Maximum ratio of EBITDAX to cash interest expense | Rate	100.00%
Federal Funds Effective Rate
Debt Instrument [Line Items]
Adjusted LIBO rate (as a percent) | Rate	0.50%
Adjusted London Inter Bank Offer Rate
Debt Instrument [Line Items]
Adjusted LIBO rate (as a percent) | Rate	1.00%
10% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Principal amount										$ 200,000,000	$ 150,000,000
Stated interest rate (as a percent)	10.00%								10.00%	10.00%
Adjusted interest on notes payable	$ 11,700,000
Credit Agreement
Debt Instrument [Line Items]
Revolving credit facility	300,000,000
Bank debt	0
Letters of credit outstanding, amount	0
Current borrowing base	$ 55,000,000
Borrowing capacity utilization, expected, percent (first quarter of 2016)	25.00%
Borrowing capacity utilization, expected amount (first quarter of 2016)	$ 10,500,000
Number of additional borrowing base re-determinations | determination	2
Minimum amount outstanding held by lenders for borrowing base approval, percent	66.70%
Credit Agreement | Letters of credit
Debt Instrument [Line Items]
Revolving credit facility	$ 25,000,000
Period minimum for refinanced debt after original maturity date	180 days
Credit Agreement | Alternate Base Rate | Maximum
Debt Instrument [Line Items]
Adjusted LIBO rate (as a percent) | Rate	2.00%
Credit Agreement | Alternate Base Rate | Minimum
Debt Instrument [Line Items]
Adjusted LIBO rate (as a percent) | Rate	1.00%
Credit Agreement | Adjusted London Inter Bank Offer Rate
Debt Instrument [Line Items]
Variable rate, floor	0.00%
Credit Agreement | Adjusted London Inter Bank Offer Rate | Maximum
Debt Instrument [Line Items]
Adjusted LIBO rate (as a percent) | Rate	3.00%
Credit Agreement | Adjusted London Inter Bank Offer Rate | Minimum
Debt Instrument [Line Items]
Adjusted LIBO rate (as a percent) | Rate	2.00%
Scenario, Forecast | Credit Agreement
Debt Instrument [Line Items]
Debt to EBITDAX ratio, when unused availability greater or equal 75 percent			5.75	5.75	5.5	5
Debt to EBITDAX ratio, when unused availability less than 75 percent		5	5.25	5.75	5.75	5.75
Subsequent Event | Credit Agreement
Debt Instrument [Line Items]
Current borrowing capacity								$ 42,000,000
Subsequent Event | Private Exchange Offer and Consent Solicitation
Debt Instrument [Line Items]
Adjusted interest on notes payable							$ 4,500,000
Oklahoma | Credit Agreement
Debt Instrument [Line Items]
Reduction in borrowing base as result of sale of oil and gas assets (on or prior to March 31, 2016)	$ 10,000,000

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 10,000
Goodson
Related Party Transaction [Line Items]
Proceeds from affiliates	(45,000)
Payments of distributions to related parties		$ 80,000	$ 92,000
Related expenses related to transactions with related party	0	18,200	0
Green
Related Party Transaction [Line Items]
Payments of distributions to related parties	30,000	$ 116,000	269,000
Nordberg
Related Party Transaction [Line Items]
Due from affiliates	$ (300)		$ (200)

Ceiling Test Write-down (Detail

Ceiling Test Write-down (Details) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)$ / mcf$ / bbl$ / Mcfe	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Rate for discounting future cash flows					10.00%
Ceiling test write-down					$ 266,562	$ 0	$ 0
Ceiling test write-downs decrease	$ 51,944	$ 40,200	$ 65,500	$ 108,900
Mcf of natural gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices | $ / mcf					2.42
Barrel of oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices | $ / bbl					50.29
Mcfe of Ngl
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices | $ / Mcfe					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 (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income [Roll Forward]
Balance. beginning of period	$ 5,420	$ (1,096)
Other comprehensive income before reclassifications:
Change in fair value of derivatives		6,683
Income tax effect		(2,079)
Net of tax		4,604
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales		3,044
Income tax effect		(1,132)
Net of tax		1,912
Net other comprehensive income		6,516
Balance, end of period	947	5,420
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income [Roll Forward]
Balance. beginning of period	5,420	(688)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	9,991	6,683
Income tax effect	(3,716)	(2,487)
Net of tax	6,275	4,196
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(17,114)	3,044
Income tax effect	6,366	(1,132)
Net of tax	(10,748)	1,912
Net other comprehensive income	(4,473)	6,108
Balance, end of period	947	5,420
Change in Valuation Allowance
Accumulated Other Comprehensive Income [Roll Forward]
Balance. beginning of period	$ 0	(408)
Other comprehensive income before reclassifications:
Income tax effect		408
Net of tax		408
Amounts reclassified from accumulated other comprehensive income:
Income tax effect		0
Net of tax		0
Net other comprehensive income		408
Balance, end of period		$ 0

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2025
Income Taxes (Textual) [Abstract]
Income taxes at a statutory rate	35.00%	35.00%	35.00%
Cumulative loss period	3 years
Deferred Tax Assets, Valuation Allowance	$ 143,508	$ 33,295	$ 45,531
Operating loss carryforwards	77,100
Share-based Compensation
Income Taxes (Textual) [Abstract]
Operating loss carryforwards	12,600
Depletion Deduction
Income Taxes (Textual) [Abstract]
Depletion deduction carryforward	$ 30,300
Scenario, Forecast
Income Taxes (Textual) [Abstract]
Operating loss carryforwards				$ 8,700

Income Taxes (Details 1) (Detai

Income Taxes (Details 1) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 24,014	$ 17,705	$ 21,810
Percentage depletion carryforward	10,592	10,206	8,645
Alternative minimum tax credits	784	784	784
Contributions carryforward and other	266	241	189
Oil and gas properties	90,291	(15,439)	(7,248)
Asset retirement obligation	15,831	20,449	18,056
Derivatives	(561)	(3,211)	408
Share-based compensation	2,291	2,560	2,887
Valuation allowance	(143,508)	(33,295)	(45,531)
Deferred taxes	$ 0	$ 0	$ 0

Income Taxes (Details 2) (Detai

Income Taxes (Details 2) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Amount computed using the statutory rate	$ (102,257)	$ 9,887	$ 5,041
State & local taxes	(6,477)	904	317
Percentage depletion carryforward	(404)	(1,564)	(1,323)
Non-deductible stock option expense	90	213	115
Share-based compensation	1,317	90	780
Other	113	(643)	1,132
Change in valuation allowance	110,244	(11,828)	(5,742)
Income tax expense (benefit)	$ 2,626	$ (2,941)	$ 320

Commitments and Contingencies71

Commitments and Contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,015	$ 1,419
2,016	1,310
2,017	452
2,018	422
2,019	417
Thereafter	1,225
Total	5,245
Operating leases rent expense	$ 1,700	$ 1,600	$ 1,400

Supplementary Information on 72

Supplementary Information on Oil and Gas Operations—Unaudited - Costs Incurred (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / Mcfe	Dec. 31, 2014USD ($)$ / Mcfe	Dec. 31, 2013USD ($)$ / Mcfe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Acquisition costs: Proved	$ 2,287	$ 3,064	$ 177,880
Acquisition costs: Unproved	2,550	39,164	35,008
Exploration costs: Proved	29,322	67,297	34,344
Exploration costs: Unproved	7,677	13,515	20,112
Development costs	9,888	55,722	41,328
Capitalized general and administrative and interest costs	12,881	22,121	19,911
Total costs incurred	64,605	200,883	328,583
Movement in Accumulated Depreciation, Depletion and Amortization [Roll Forward]
Balance, beginning of year	(1,648,060)	(1,553,044)	(1,472,244)
Provision for DD&A	(62,138)	(86,406)	(69,357)
Ceiling test writedown	(266,562)	0	0
Sale of proved properties and other	819,305	(8,610)	(11,443)
Balance, end of year	$ (1,157,455)	$ (1,648,060)	$ (1,553,044)
DD&A per Mcfe (usd per mcfe) | $ / Mcfe	1.82	1.99	1.82

Supplementary Information on 73

Supplementary Information on Oil and Gas Operations—Unaudited - Investment in Oil and Gas Properties - Unaudited (Textuals) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Jun. 30, 2014USD ($)a	Dec. 31, 2015USD ($)Wells	Dec. 31, 2014USD ($)a	Dec. 31, 2013USD ($)aWells
Reserve Quantities [Line Items]
Sale of oil and gas properties		$ 271,769	$ 11,908	$ 20,400
Unevaluated oil and gas properties		12,500	109,100
Interest costs capitalized		$ 4,700	10,000	6,600
Expected period to evaluate existing unevaluated properties		3 years
Unevaluated costs expected to be evaluated in 2015		$ 200
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
Woodford
Reserve Quantities [Line Items]
Sale of oil and gas properties				$ 10,400
Percent of saltwater disposal systems and related surface assets sold				50.00%
Wyoming
Reserve Quantities [Line Items]
Sale of oil and gas properties				$ 1,000
Uncompleted Wells Equipment and Facilities
Reserve Quantities [Line Items]
Unevaluated oil and gas properties		$ 200		$ 16,800
Exploratory wells drilled, unevaluated | Wells		2		16
2,012
Reserve Quantities [Line Items]
Unevaluated oil and gas properties		$ (3,100)
Percentage of unevaluated costs capitalized in period		(25.00%)
2,011
Reserve Quantities [Line Items]
Unevaluated oil and gas properties			$ 3,600
Percentage of unevaluated costs capitalized in period			29.00%
Prior to 2011
Reserve Quantities [Line Items]
Unevaluated oil and gas properties				$ 12,100
Percentage of unevaluated costs capitalized in period				96.00%
Gulf of Mexico Acquisition
Reserve Quantities [Line Items]
Unevaluated acres acquired | a				13,500
10% Senior Notes | Gulf of Mexico Acquisition
Reserve Quantities [Line Items]
Purchase price				$ 188,800
Louisiana | Fleetwood Joint Venture
Reserve Quantities [Line Items]
Aggregate purchase price	$ 24,000		$ 24,000
Number of acres acquired | a	30,000		30,000
Purchase price	$ 10,000
Woodford And Mississippian Lime
Reserve Quantities [Line Items]
Sale of oil and gas properties		$ 274,100

Supplementary Information on 74

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, 2015McfeMBblsMMcf	Dec. 31, 2014McfeMBblsMMcf	Dec. 31, 2013McfeMBblsMMcf
Oil
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MBbls	2,437	3,031	1,635
Revisions of previous estimates | MBbls	(211)	(37)	(156)
Extensions, discoveries and other additions | MBbls	163	475	434
Purchase of producing properties | MBbls			1,833
Sale of reserves in place | MBbls	(54)	(229)	(34)
Production | MBbls	(529)	(803)	(681)
Proved reserves ending balance | MBbls	1,806	2,437	3,031
Proved developed reserves | MBbls	1,549	2,089	2,709
Proved undeveloped reserve | MBbls	257	348	322
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	73,498	28,430	24,366
Revisions of previous estimates	(3,571)	2,894	804
Extensions, discoveries and other additions	16,078	49,990	6,099
Purchase of producing properties			1,915
Sale of reserves in place	(45,692)	(334)	0
Production	(5,487)	(7,482)	(4,754)
Proved reserves, ending balance	34,826	73,498	28,430
Proved undeveloped reserve	15,792	42,584	23,173
Proved developed reserves	19,034	30,914	5,257
Natural Gas
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MMcf	309,025	250,109	188,264
Revisions of previous estimates | MMcf	(9,852)	9,976	38,383
Extensions, discoveries and other additions | MMcf	45,645	82,364	30,429
Purchase of producing properties | MMcf			22,274
Sale of reserves in place | MMcf	(186,972)	(2,396)	(15)
Production | MMcf	(25,502)	(31,028)	(29,226)
Proved reserves ending balance | MMcf	132,344	309,025	250,109
Proved developed reserves | MMcf	78,533	182,567	163,728
Proved undeveloped reserve | MMcf	53,811	126,458	86,381
Oil and Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	397,148	296,723	222,441
Revisions of previous estimates	(14,698)	12,650	38,247
Extensions, discoveries and other additions	62,702	135,205	39,132
Purchase of producing properties			35,187
Sale of reserves in place	(232,988)	(4,105)	(218)
Production	(34,160)	(43,325)	(38,066)
Proved reserves, ending balance	178,004	397,148	296,723
Proved undeveloped reserve	103,615	237,688	203,152
Proved developed reserves	74,389	159,460	93,571

Supplementary Information on 75

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, 2015McfeWells$ / mcf$ / bbl$ / McfeMBblsMMcf	Dec. 31, 2014McfeWells$ / mcf$ / bbl$ / McfeMBblsMMcf	Dec. 31, 2013Mcfe$ / mcf$ / bbl$ / McfeMBblsMMcf	Dec. 31, 2012$ / mcf
Reserve Quantities [Line Items]
Company drilling success rate	95.00%	91.00%
Gross wells drilled | Wells	56	58
Oklahoma
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)	17,000	72,000	23,000
Texas
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)	44,000	46,000	10,000
Gulf Coast
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)		15,000	5,000
Oil
Reserve Quantities [Line Items]
Number of Bcfe additions | MBbls	163	475	434
Consolidated oil and gas production costs per unit of production | $ / bbl	50.29	96.45	106.19
Natural Gas Liquids
Reserve Quantities [Line Items]
Extensions, discoveries and other additions of Bcfe	16,078	49,990	6,099
Consolidated oil and gas production costs per unit of production | $ / Mcfe	2.24	4.11	5.10
Oil and Natural Gas Reserves
Reserve Quantities [Line Items]
Increase in proved developed and undeveloped reserves	(55.00%)	33.84053%
Extensions, discoveries and other additions of Bcfe	62,702	135,205	39,132
Natural Gas
Reserve Quantities [Line Items]
Number of Bcfe additions | MMcf	45,645	82,364	30,429
Consolidated oil and gas production costs per unit of production | $ / mcf	2.41	3.80	3.11	2.20
Gulf of Mexico Acquisition
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)			35,000

Supplementary Information on 76

Supplementary Information on Oil and Gas Operations—Unaudited - Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows [Abstract]
Future cash flows	$ 487,834	$ 1,711,404	$ 1,243,627
Future production costs	(171,678)	(372,690)	(295,666)
Future development costs	(116,591)	(244,784)	(185,188)
Future income taxes	0	(121,192)	(37,404)
Future net cash flows	199,565	972,738	725,369
10% annual discount	(71,880)	(424,176)	(274,189)
Standardized measure of discounted future net cash flows	$ 127,685	$ 548,562	$ 451,180	$ 230,823

Supplementary Information on 77

Supplementary Information on Oil and Gas Operations—Unaudited - Changes in Standardized Measure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 548,562	$ 451,180	$ 230,823
Sales and transfers of oil and gas produced, net of production costs	(55,849)	(173,540)	(134,184)
Changes in price, net of future production costs	(267,710)	37,204	55,601
Extensions and discoveries, net of future production and development costs	70,928	237,290	70,181
Changes in estimated future development costs, net of development costs incurred during this period	31,007	11,094	(25,389)
Revisions of quantity estimates	(14,427)	25,591	58,508
Accretion of discount	60,071	47,130	23,776
Net change in income taxes	52,149	(32,034)	(13,182)
Purchase of reserves in place	0	0	191,964
Sale of reserves in place	(194,454)	(7,240)	(411)
Changes in production rates (timing) and other	(102,592)	(48,113)	(6,507)
Net increase (decrease) in standardized measure	(420,877)	97,382	220,357
Standardized measure at end of year	$ 127,685	$ 548,562	$ 451,180

Summarized Quarterly Financia78

Summarized Quarterly Financial Information—Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 23,096	$ 26,872	$ 32,550	$ 33,451	$ 47,988	$ 56,486	$ 60,581	$ 59,966
Loss from operations	(61,864)	(50,617)	(57,796)	(121,887)	478	5,569	10,879	11,323	$ (292,164)	$ 28,249	$ 14,402
Loss available to common stockholders	$ (64,696)	$ (51,910)	$ (61,083)	$ (122,240)	$ 1,745	$ 4,671	$ 9,592	$ 10,043	$ (299,929)	$ 26,051	$ 8,943
Earnings per share, Basic (in usd per share)	$ (0.98)	$ (0.80)	$ (0.94)	$ (1.89)	$ 0.02	$ 0.07	$ 0.15	$ 0.15	$ (4.61)	$ 0.39	$ 0.14
Earnings per share, Diluted (in usd per share)	$ (0.98)	$ (0.80)	$ (0.94)	$ (1.89)	$ 0.02	$ 0.07	$ 0.15	$ 0.15	$ (4.61)	$ 0.39	$ 0.14
Ceiling test write-downs	$ 51,944	$ 40,200	$ 65,500	$ 108,900
Gain on sale of assets			$ 21,500						$ 21,937	$ 0	$ 0