Petroquest Energy (PQ) 10-K 6 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 26, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	872248
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		65,863,474
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$321

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$18,243	$9,153
Revenue receivable	16,485	26,568
Joint interest billing receivable	46,778	26,556
Derivative asset	8,631	521
Prepaid drilling costs	847	477
Other current assets	5,566	8,132
Total current assets	96,550	71,407
Oil and gas properties:
Oil and gas properties, full cost method	2,222,753	2,035,899
Unevaluated oil and gas properties	109,119	98,387
Accumulated depreciation, depletion and amortization	-1,648,060	-1,553,044
Oil and gas properties, net	683,812	581,242
Other property and equipment	14,953	13,993
Accumulated depreciation of other property and equipment	-10,313	-8,901
Total property and equipment	688,452	586,334
Other assets, net of accumulated amortization of $7,847 and $5,689, respectively	5,893	9,449
Total assets	790,895	667,190
Current liabilities:
Accounts payable to vendors	102,954	47,341
Advances from co-owners	12,819	969
Oil and gas revenue payable	22,333	22,664
Accrued interest and preferred stock dividend	12,764	12,909
Asset retirement obligation	2,756	3,113
Derivative liability	0	1,617
Accrued acquisition costs	17,690	0
Other accrued liabilities	5,394	8,924
Total current liabilities	176,710	97,537
Bank debt	75,000	75,000
10% Senior Notes	350,000	350,000
Asset retirement obligation	52,214	45,423
Other long-term liability	62	135
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 64,721 and 63,664 shares, respectively	65	64
Paid-in capital	285,957	280,711
Accumulated other comprehensive income (loss)	5,420	-1,096
Accumulated deficit	-154,534	-180,585
Total stockholders’ equity	136,909	99,095
Total liabilities and stockholders’ equity	$790,895	$667,190

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Debt Instrument [Line Items]
Accumulated depreciation and amortization	$7,847	$5,689
Preferred stock, par value (usd per share)	$0.00	$0.00
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)	$0.00	$0.00
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	64,721,000	63,664,000
Common stock, shares outstanding	64,721,000	63,664,000
10% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate (as a percent)	10.00%	10.00%

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil and gas sales	$225,021	$182,804	$141,433
Expenses:
Lease operating expenses	48,597	43,743	38,890
Production taxes	5,927	3,950	885
Depreciation, depletion and amortization	87,818	71,445	60,689
Ceiling test write-down	0	0	137,100
General and administrative	22,870	26,512	22,957
Accretion of asset retirement obligation	2,958	1,753	2,078
Interest expense	29,281	21,886	9,808
Total expenses	197,451	169,289	272,407
Other income (expense):
Other income	679	654	764
Derivative income (expense)	0	233	-233
Other income (expense), net	679	887	531
Income (loss) from operations	28,249	14,402	-130,443
Income tax expense (benefit)	-2,941	320	1,636
Net income (loss)	31,190	14,082	-132,079
Preferred stock dividend	5,139	5,139	5,139
Net income (loss) available to common stockholders	$26,051	$8,943	($137,218)
Basic
Net income (loss) per share (in usd per share)	$0.39	$0.14	($2.20)
Diluted
Net income (loss) per share (in usd per share)	$0.39	$0.14	($2.20)
Weighted average number of common shares:
Basic (shares)	64,204	63,054	62,459
Diluted (shares)	64,225	63,208	62,459

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income (loss)	$31,190	$14,082	($132,079)
Change in fair value of derivatives, net of income tax (expense) benefit of ($3,211), $309 and $2,079 respectively	6,516	-1,617	-3,510
Comprehensive income (loss)	$37,706	$12,465	($135,589)

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net of income taxes	$3,211	$309	$2,079

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	$31,190	$14,082	($132,079)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)	-2,941	320	1,636
Depreciation, depletion and amortization	87,818	71,445	60,689
Ceiling test write-down	0	0	137,100
Accretion of asset retirement obligation	2,958	1,753	2,078
Share based compensation expense	5,248	4,216	6,910
Amortization costs and other	2,188	1,473	881
Non-cash derivative expense (income)	0	-233	233
Payments to settle asset retirement obligations	-3,623	-3,335	-2,627
Changes in working capital accounts:
Revenue receivable	10,083	-8,826	-1,882
Prepaid drilling and pipe costs	-370	1,221	4,479
Joint interest billing and other receivable	-20,276	15,685	3,981
Accounts payable and accrued liabilities	50,243	-12,865	20,916
Advances from co-owners	11,850	-19,490	-13,408
Other	3,840	-5,592	-316
Net cash provided by operating activities	178,208	59,854	88,591
Cash flows used in investing activities:
Investment in oil and gas properties	-174,633	-298,824	-147,771
Investment in other property and equipment	-926	-1,679	-1,743
Sale of oil and gas properties	8,610	19,913	837
Sale of unevaluated oil and gas properties	3,298	487	8,889
Net cash used in investing activities	-163,651	-280,103	-139,788
Cash flows used in financing activities:
Net payments for share based compensation	-75	-38	-981
Deferred financing costs	-253	-320	-42
Payment of preferred stock dividend	-5,139	-5,139	-5,139
Proceeds from bank borrowings	17,500	73,000	102,500
Repayment of bank borrowings	-17,500	-48,000	-52,500
Proceeds from issuance of 10% Senior Notes	0	200,000	0
Costs to issue 10% Senior Notes	0	-5,005	0
Net cash provided by (used in) financing activities	-5,467	214,498	43,838
Net increase (decrease) in cash and cash equivalents	9,090	-5,751	-7,359
Cash and cash equivalents, beginning of period	9,153	14,904	22,263
Cash and cash equivalents, end of period	18,243	9,153	14,904
Cash paid during the period for:
Interest	37,174	20,101	16,026
Income taxes	$270	$12	$105

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (USD $)	Total	Common Stock	Preferred Stock	Paid-In Capital	Other Comprehensive Income (Loss)	Accumulated Deficit
In Thousands, unless otherwise specified
Beginning stockholders' equity at Dec. 31, 2011	$222,390	$62	$1	$270,606	$4,031	($52,310)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Options exercised	260			260
Retirement of shares upon vesting of restricted stock	-1,241	1		-1,242
Share-based compensation expense	6,910			6,910
Derivative fair value adjustment, net of tax	-3,510				-3,510
Preferred stock dividend	-5,139					-5,139
Net income (loss)	-132,079					-132,079
Ending 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
Share-based compensation expense	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
Share-based compensation expense	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)

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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 Oklahoma and Texas as well as onshore and in the shallow waters offshore the Gulf Coast Basin.
	Principles of Consolidation
	The Consolidated Financial Statements include the accounts of PetroQuest and its subsidiaries, PetroQuest Energy, L.L.C., PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC (collectively, the "Company"). All intercompany accounts and transactions have been eliminated. Certain prior period amounts have been reclassified to conform to current year presentation.
	Use of Estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	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 should be 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. As of December 31, 2014 and 2013, the Company had $0.1 million recorded related to an allowance for doubtful accounts on its joint interest billing receivable.
	Other Current Assets
	Other current assets at December 31, 2014 and 2013 included $0.9 million and $3.1 million, respectively, related to an insurance receivable with respect to an operational related claim in our Oklahoma acreage.
	Other Property and Equipment
	During 2006, the Company acquired a gas gathering system used in the transportation of natural gas. The costs related to this system are depreciated on a straight line basis over the estimated remaining useful life, generally 14 years. The costs related to other furniture and fixtures are depreciated on a straight line basis over estimated useful lives ranging from 3-8 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, 2014 and 2013 included $5.5 million and $7.4 million, respectively, related to deferred financing costs, which are amortized over the life of the related debt.
	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. Gas imbalances as of December 31, 2014 and 2013 were not significant.
	Certain 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,
			2014		2013		2012
	Shell Trading Co.		30	%	35	%	30	%
	Laclede Energy		24	%	14	%	17	%
	Unimark, LLC		14	%	14	%	(a)
	JP Morgan Ventures Energy		(a)		(a)		12	%
	(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 income statement 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 ($3.0) million, $0.9 million and $9.1 million during 2014, 2013 and 2012, respectively.
	The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas and OPIS Mt. Bellevue pricing for natural gas liquids. 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 and OPIS Mt. Bellevue 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 and OPIS Mt. Bellevue prices at which the hedges will be settled. At December 31, 2014, the Company’s derivative instruments were designated as effective cash flow hedges. See Note 7 for further discussion of the Company’s derivative instruments.
	Recently Issued Accounting Standards
	In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements.  The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods and or services.  The standard is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years.  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.  We are currently evaluating the effect that this new standard will have on our consolidated financial statements and related disclosures, however, we do not expect the adoption of the standard will have a material impact on our results of operations, financial position, or related disclosures.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	Acquisitions
	Gulf of Mexico Acquisition:
	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.  The Company subsequently registered the 10% Senior Notes due 2017 in an exchange offer completed in September 2013 (the "New Notes"). The New Notes are substantially identical to the Company's existing $150 million aggregate principal amount of 10% Senior Notes due 2017. In connection with the transaction, the Company recorded $5 million of deferred financing costs related to the New Notes 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 and 2012 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				2012
	Revenues	$	215,666			$	187,104
	Income (Loss) from Operations	19,858				(135,406		)
	Net Income (Loss) available to common stockholders	14,399				(142,181		)
	Basic Earnings (loss) per Share	$	0.22			$	(2.28	)
	Diluted Earnings (loss) per Share	$	0.22			$	(2.28	)
	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. If the $14 million in drilling, completion and lease acquisition costs is not fully funded by December 31, 2015, any remaining balance becomes payable at the election of our joint venture partner. At December 31, 2014, $7.0 million of the cash purchase price and $10.7 million of the cash funding for future drilling, completion and lease acquisition costs remained outstanding. The total liability of $17.7 million at December 31, 2014 is reflected as accrued acquisition costs in the Consolidated Balance Sheet.

Convertible_Preferred_Stock

Convertible Preferred Stock	12 Months Ended
	Dec. 31, 2014
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.
	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, 2014
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, 2014	Income (Numerator)			Shares	Per
					(Denominator)	Share Amount
	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
					(Denominator)	Share Amount
	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
	For the Year Ended December 31, 2012	Loss			Shares	Per
		(Numerator)			(Denominator)	Share Amount
	BASIC EPS
	Net loss available to common stockholders	$	(137,218	)	62,459	$	(2.20	)
	Effect of dilutive securities:
	Stock options	—			—
	Restricted stock	—			—
	DILUTED EPS	$	(137,218	)	62,459	$	(2.20	)
	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.
	An aggregate of 0.9 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the year ended December 31, 2012, because the inclusion would have been anti-dilutive as a result of the net loss reported for the year.

ShareBased_Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012 is as follows (in thousands):
			Year Ended December 31,
			2014				2013			2012
	Stock options:
	Incentive Stock Options		$	573			$	310		$	786
	Non-Qualified Stock Options		171				222			660
	Restricted stock		4,504				3,684			5,464
	Restricted stock units		3,094				1,611			277
	Share-based compensation		$	8,342			$	5,827		$	7,187
	During the years ended December 31, 2014, 2013 and 2012 the Company capitalized $1.5 million, $0.8 million and $0.1 million of the above share-based compensation cost to oil and gas properties. During the years ended December 31, 2014, 2013 and 2012, the Company recorded income tax benefits of approximately $2.3 million, $1.8 million and $2.3 million, respectively, related to share-based compensation expense recognized during those periods. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred and the Company has net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for any periods presented.
	At December 31, 2014, the Company had $7.6 million of unrecognized compensation cost related to unvested restricted stock and stock options. This amount will be recognized as compensation expense over a weighted average period of approximately three years.
	Stock Options
	Stock options 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.
	The following table outlines the assumptions used in computing the fair value of stock options granted during 2014, 2013 and 2012:
			Years Ended December 31,
			2014		2013		2012
	Dividend yield		—%		—%		—%
	Expected volatility		79.4% - 80.0%		79.6% - 79.8%		79.2% - 79.6%
	Risk-free rate		1.81% - 2.015%		0.9% - 1.815%		0.8% - 1.1%
	Expected term		6 years		6 years		6 years
	Forfeiture rate		5.00%		5.00%		5.00%
	Stock options granted (1)		69,434		395,642		125,487
	Wgtd. avg. grant date fair value per share		$2.84		$2.91		$3.71
	Fair value of grants (1)		$197,000		$1,150,000		$465,000
	-1	Prior to applying estimated forfeiture rate
	The following table details stock option activity during the year ended December 31, 2014:
			Number of			Wgtd. Avg.			Wgtd. Avg.		Aggregate
			Options			Exercise  Price			Remaining  Life		Intrinsic  Value
											(000’s)
	Outstanding at beginning of year		1,892,493			$	5.67
	Granted		69,434			4.13
	Expired/cancelled/forfeited		(156,724	)		5.6
	Exercised		(287,499	)		3.34
	Outstanding at end of year		1,517,704			6.05			6.0 years		$	—
	Options exercisable at end of year		1,172,400			$	6.58		5.3 years		$	—
	Options expected to vest		328,039			4.27			8.6 years		$	—
	The total fair value of stock options that vested during the years ended December 31, 2014, 2013 and 2012 was $1.0 million, $0.8 million and $1.7 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, 2014:
	Range of		Options			Wgtd. Avg.		Wgtd. Avg.	Options			Wgtd. Avg.
	Exercise		Outstanding			Remaining		Exercise	Exercisable			Exercise
	Price		12/31/14			Contractual Life		Price	12/31/14			Price
	$2.24—$4.48		407,255			8.9 years		$4.14	115,945			$4.18
	$4.48—$6.72		355,820			4.0 years		$5.63	301,826			$5.73
	$6.72—$8.96		744,629			5.5 years		$7.25	744,629			$7.25
	$8.96—$11.20		10,000			1.1 years		$9.99	10,000			$9.99
			1,517,704			6.0 years		$6.05	1,172,400			$6.58
	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. Prior to 2013, restricted stock granted to directors generally vested evenly over a three year period. In 2013, restricted stock granted to directors vests one year from the date of grant, to align with their term on the board. Beginning January 1, 2011, restricted stock granted to employees generally vests evenly over a three year period. 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, 2014:
			Number of			Wgtd. Avg.
			Shares			Fair Value  per
						Share
	Outstanding at beginning of year		1,926,451			$	4.88
	Granted		1,599,750			4.32
	Expired/cancelled/forfeited		(135,861	)		5.01
	Lapse of restrictions		(962,138	)		5.22
	Outstanding at December 31, 2014		2,428,202			$	4.37
	The weighted average grant date fair value of restricted stock granted during the years ended December 31, 2014, 2013 and 2012 was $4.32, $4.18 and $5.24, respectively, per share. The total fair value of restricted stock that vested during the years ended December 31, 2014, 2013 and 2012 was $5.0 million, $5.4 million and $4.7 million, respectively. At December 31, 2014, the weighted average remaining life of restricted stock outstanding was approximately two years and the intrinsic value of restricted stock outstanding, using the closing stock price on December 31, 2014, was $9.4 million.
	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 2014, the Company paid $2.0 million for units that vested during the period. As of December 31, 2014, the Company had a liability for RSUs outstanding and expected to vest in the amount of $1.4 million.
	The following table details RSU activity during the year ended December 31, 2014:
		Number of Shares
Outstanding at beginning of year	1,273,417
Granted	669,469
Expired/Cancelled/Forfeited	(66,849	)
Vested/Paid	(496,776	)
Outstanding at December 31, 2014	1,379,261
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 could 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 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. The liability for MSRUs was immaterial as of December 31, 2014.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013
	Asset retirement obligation, beginning of period	$	48,536		$	27,260
	Liabilities assumed	—			15,319
	Liabilities incurred	756			498
	Liabilities settled	(3,623		)	(3,335		)
	Accretion expense	2,958			1,753
	Revisions in estimated cash flows	6,343			7,041
	Asset retirement obligation, end of period	54,970			48,536
	Less: current portion of asset retirement obligation	(2,756		)	(3,113		)
	Long-term asset retirement obligation	$	52,214		$	45,423

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013, all of the Company's outstanding derivative instruments were designated as cash flow hedges. At December 31, 2012, all of the Company's outstanding derivative instruments were designated as cash flow hedges, except its three-way collar discussed below.
	Oil and gas sales include additions (reductions) related to the settlement of gas hedges of ($4,237,000), $1,098,000 and $6,846,000, Ngl hedges of $296,000, $61,000 and $722,000, and oil hedges of $897,000, ($232,000) and $1,529,000, for the years ended December 31, 2014, 2013 and 2012, respectively.
	As of December 31, 2014, the Company had entered into the following gas hedge contracts:
	Production Period		Instrument Type		Daily Volumes		Weighted Average Price
	Natural Gas:
	2015		Swap		30,000 Mmbtu		$3.82
	At December 31, 2014, the Company had recognized an asset of approximately $8.6 million related to the estimated fair value of these derivative contracts. Based on estimated future commodity prices as of December 31, 2014, the Company would realize a $5.4 million gain, net of taxes, during the next 12 months. These gains are expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts.
	During January and February 2015, the Company entered into the following additional derivative contracts accounted for as a cash flow hedges:
	Production Period		Instrument Type		Daily Volumes		Weighted Average Price
	Natural Gas:
	February - December 2015		Swap		10,000 Mmbtu		$2.93
	July 2015 - June 2016		Swap		10,000 Mmbtu		$3.22
	March 2015 - December 2015		Swap		15,000 Mmbtu		$2.99
	Crude Oil:
	February - December 2015		Swap (LLS)		250 Bbls		$54.00
	March 2015 - December 2015		Swap (LLS)		250 Bbls		$59.35
	Propane:
	March 2015 - December 2015		Swap		250 Bbls		$25.62
	LLS - Louisiana Light Sweet
	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, 2014 and December 31, 2013:
		Commodity Derivatives
	Period	Balance Sheet	Fair Value
		Location
	December 31, 2014	Derivative asset	$	8,631
	December 31, 2013	Derivative asset	$	521
	December 31, 2013	Derivative liability	$	(1,617	)
	Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2014, 2013 and 2012:
	Instrument	Amount of Gain (Loss)				Location of		Amount of Gain (Loss) Reclassified into
		Recognized in Other				Gain Reclassified		Income
		Comprehensive Income				into Income
	Commodity Derivatives at December 31, 2014	$	6,516			Oil and gas sales		$	(3,044	)
	Commodity Derivatives at December 31, 2013	$	(1,617	)		Oil and gas sales		$	927
	Commodity Derivatives at December 31, 2012	$	(3,510	)		Oil and gas sales		$	9,097
	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 gains and losses on this contract were recorded as derivative expense (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 years ended December 31, 2013 and 2012:
	Instrument	Amount of Gain (Loss)
		Recognized in Derivative
		Income (Expense)
	Commodity Derivatives at December 31, 2013	$	233
	Commodity Derivatives at December 31, 2012	$	(233	)

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 were in the form of swaps based on NYMEX pricing for oil and natural gas. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.
	The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis as of December 31, 2014 and December 31, 2013 (in thousands):
		Fair Value Measurements Using
	Instrument	Quoted Prices		Significant Other			Significant
		in Active		Observable			Unobservable
		Markets (Level 1)		Inputs (Level 2)			Inputs (Level 3)
	Commodity Derivatives:
	At December 31, 2014	$	—	$	8,631		$	—
	At December 31, 2013	$	—	$	(1,096	)	$	—
	The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at December 31, 2014 and 2013. The fair value of the Company's $350 million 10% Senior Notes due 2017 (the "Notes") was approximately $301 million and $364 million as of December 31, 2014 and 2013, 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.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt
	On August 19, 2010, PetroQuest issued $150 million in principal amount of Notes (the "Existing Notes") in a public offering. On July 3, 2013, PetroQuest issued an additional $200 million in aggregate principal amount of Notes. PetroQuest subsequently registered the Notes in an exchange offer completed in September 2013 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of their face value plus accrued interest from March 1, 2013 and are substantially identical to the Existing Notes. The net proceeds from the offering were used to finance the $188.8 million aggregate cash purchase price of the Gulf of Mexico Acquisition, which also closed on July 3, 2013. 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.
	The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At December 31, 2014, $11.7 million had been accrued in connection with the March 1, 2015 interest payment 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 (collectively the “Lenders”). The Credit Agreement provides the Borrower 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 Borrower to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 3, 2016. As of December 31, 2014, the Borrower had $75.0 million of borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.
	The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to the Borrower's oil and gas properties as of January 1 and July 1 of each year. On September 29, 2014 the borrowing base was increased from $200 million to $220 million (subject to the aggregate commitments of the Lenders then in effect). As of December 31, 2014, the aggregate commitments of the Lenders is $170 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing Lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur by March 31, 2015. The Borrower or the Lenders may request two additional borrowing base redeterminations 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 80% 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 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% 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 plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. 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 Borrower) 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 Borrower 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 a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 3.5 to 1.0, and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. 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. However, the Credit Agreement permits the Borrower to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, as long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the Lenders at such time. As of December 31, 2014, the Borrower was in compliance with all of the covenants contained in the Credit Agreement.
	During February 2015, the Company and the Lenders amended the Credit Agreement in order to modify certain restrictive financial covenants. Specifically, the amendment removed the 3.5 to 1.0 maximum ratio of total debt to EBITDAX and replaced that with a maximum ratio of total senior secured debt to EBITDAX, determined on a rolling four quarter basis, not to exceed 2.25 to 1.0. In addition, the amendment added a minimum ratio of EBITDAX to total cash interest expense, determined on a rolling four quarter basis, of 2.0 to 1.0. The modification to the covenants described above will become effective with the quarter ended March 31, 2015 and will remain in effect through the Credit Agreement's maturity in October 2016.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
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 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. During 2012, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green and Nordberg, or their affiliates, in the amounts of $104,000, $387,000, and $100, respectively. 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, 2014, the Company’s joint interest billing receivable included approximately $5,000 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, 2014.
	Periodically, the Company charters private aircraft for business purposes. During 2014 and 2012, the Company paid approximately $18,200 and $16,900, respectively, 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 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_Writedown

Ceiling Test Write-down	12 Months Ended
	Dec. 31, 2014
Ceiling Test [Abstract]
Ceiling Test Write-down	Ceiling Test Write-down
	As a result of low natural gas prices and their negative impact on certain of the Company’s longer-lived estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of $137.1 million during 2012. No such write-down occurred during 2014 or 2013. At December 31, 2012, 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 $2.21 per Mcf of natural gas, $102.81 per barrel of oil and $6.07 per Mcfe of Ngl. The Company’s cash flow hedges in place decreased the ceiling test write-down by approximately $2.2 million.

Other_Comprehensive_Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2014
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, 2013 (in thousands):
		Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
	Balance as of December 31, 2012	$	521		$	—		$	521
	Other comprehensive loss before reclassifications:
	Change in fair value of derivatives	(999		)				(999		)
	Income tax effect	372			(408		)	(36		)
	Net of tax	(627		)	(408		)	(1,035		)
	Amounts reclassified from accumulated other comprehensive income:
	Oil and gas sales	(927		)				(927		)
	Income tax effect	345			—			345
	Net of tax	(582		)	—			(582		)
	Net other comprehensive loss	(1,209		)	(408		)	(1,617		)
	Balance as of December 31, 2013	$	(688	)	$	(408	)	$	(1,096	)
	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 loss 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 loss	6,108			408			6,516
	Balance as of December 31, 2014	$	5,420		$	—		$	5,420
	See Note 7 for additional details about the effect of the above reclassifications.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
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 the ceiling test write-downs recognized during 2011 and 2012, the Company 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. Accordingly, the Company established a valuation allowance of $33.3 million as of December 31, 2014.
	An analysis of the Company’s deferred taxes follows (amounts in thousands):
		December 31,
		2014			2013			2012
	Net operating loss carryforwards	$	17,705		$	21,810		$	16,641
	Percentage depletion carryforward	10,206			8,645			7,317
	Alternative minimum tax credits	784			784			784
	Contributions carryforward and other	241			189			156
	Temporary differences:
	Oil and gas properties	(15,439		)	(7,248		)	12,575
	Asset retirement obligation	20,449			18,056			10,141
	Derivatives	(3,211		)	408			(222		)
	Share-based compensation	2,560			2,887			3,474
	Valuation allowance	(33,295		)	(45,531		)	(50,866		)
	Deferred taxes	$	—		$	—		$	—
	At December 31, 2014, the Company had approximately $60.2 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 $29.2 million in statutory depletion deductions that may be carried forward indefinitely.
	Income tax expense (benefit) for each of the years ended December 31, 2014, 2013 and 2012 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,
		2014			2013			2012
	Amount computed using the statutory rate	$	9,887		$	5,041		$	(45,655	)
	Increase (reduction) in taxes resulting from:
	State & local taxes	904			317			(2,870		)
	Percentage depletion carryforward	(1,564		)	(1,323		)	(1,309		)
	Non-deductible stock option expense (1)	213			115			292
	Share-based compensation (2)	90			780			9
	Other	(643		)	1,132			303
	Change in valuation allowance	(11,828		)	(5,742		)	50,866
	Income tax expense (benefit)	$	(2,941	)	$	320		$	1,636
	-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, 2014
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, 2014 under these operating leases are as follows (in thousands):
	2015	$	1,480
	2016	1,418
	2017	1,317
	2018	416
	2019	401
	Thereafter	1,631
		$	6,663
	Total rent expense under operating leases was approximately $1.6 million, $1.4 million and $1.4 million in 2014, 2013 and 2012, respectively.

Supplementary_Information_on_O

Supplementary Information on Oil and Gas Operations—Unaudited	12 Months Ended
	Dec. 31, 2014
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,
		2014				2013				2012
	Acquisition costs:
	Proved (1)	$	3,064			$	177,880			$	352
	Unproved (1)	39,164				35,008				15,677
	Divestitures—unproved (2)	(3,298		)		(487		)		(8,889		)
	Exploration costs:
	Proved	67,297				34,344				72,361
	Unproved	13,515				20,112				18,033
	Development costs	55,722				41,328				18,740
	Capitalized general and administrative and interest costs	22,121				19,911				18,961
	Total costs incurred	$	197,585			$	328,096			$	135,235
		For the Year-Ended December 31,
		2014				2013				2012
	Accumulated depreciation, depletion and amortization (DD&A)
	Balance, beginning of year	$	(1,553,044	)		$	(1,472,244	)		$	(1,265,603	)
	Provision for DD&A	(86,406		)		(69,357		)		(59,496		)
	Ceiling test writedown	—				—				(137,100		)
	Sale of proved properties and other (3)	(8,610		)		(11,443		)		(10,045		)
	Balance, end of year	$	(1,648,060	)		$	(1,553,044	)		$	(1,472,244	)
	DD&A per Mcfe	$	1.99			$	1.82			$	1.75
	-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 2012, the Company sold an additional portion of its Mississippian Lime acreage for $6.1 million.
	-3	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. During 2012, the Company sold its non-operated Arkansas assets for a net cash purchase price of $8.5 million.
	At December 31, 2014 and 2013, unevaluated oil and gas properties totaled $109.1 million and $98.4 million, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2014 included $16.8 million of costs related to 16 exploratory wells in progress at year-end. These costs are expected to be transferred to evaluated oil and gas properties during 2015 upon the completion of drilling. At December 31, 2013, unevaluated costs included $11.3 million related to 19 exploratory wells in progress. All of these costs were transferred to evaluated oil and gas properties during 2014. The Company capitalized $10.0 million, $6.6 million and $7.0 million of interest during 2014, 2013 and 2012, respectively. Of the total unevaluated oil and gas property costs of $109.1 million at December 31, 2014, $56.3 million, or 52%, was incurred in 2014, $21.1 million, or 19%, was incurred in 2013 and $31.7 million, or 29%, was incurred in prior years. The Company expects that the majority of the unevaluated costs at December 31, 2014 will be evaluated within the next 3 years, including $32.5 million that the Company expects to be evaluated during 2015.
	Oil and Gas Reserve Information
	The Company’s net proved oil and gas reserves at December 31, 2014 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
		in			in			in			Reserves
		MBbls			MMcfe			MMcf			in MMcfe
	Proved reserves as of December 31, 2011	1,395			15,111			241,926			265,407
	Revisions of previous estimates (1)	195			(1,952	)		(56,780	)		(57,561	)
	Extensions, discoveries and other additions	647			14,572			46,390			64,844
	Sale of reserves in place	(81	)		—			(15,806	)		(16,292	)
	Production	(521	)		(3,365	)		(27,466	)		(33,957	)
	Proved reserves as of December 31, 2012	1,635			24,366			188,264			222,441
	Revisions of previous estimates (1)	(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
	Purchase of producing properties	—			—			—			—
	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
	Proved developed reserves
	As of December 31, 2012	1,225			20,608			140,307			168,265
	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
	Proved undeveloped reserves
	As of December 31, 2012 (1)	410			3,758			47,957			54,176
	As of December 31, 2013 (1)	322			5,257			86,381			93,571
	As of December 31, 2014	348			30,914			126,458			159,460
	(1) The table above includes certain adjustments to previously disclosed estimated proved reserves as of December 31, 2013 and 2012. Specifically, as of December 31, 2014, the Company determined that it should have reflected additional downward revisions to certain of its proved undeveloped reserves totaling 5,088 MMcfe and 5,817 MMcfe as of December 31, 2013 and 2012, respectively. The table above reflects such adjustments of previous estimates for the years ended December 31, 2013 and 2012, respectively. The above adjustments had no material impact on the Company's financial statements for the years ended December 31, 2013 and 2012.
	Year Ended December 31, 2014
During 2014, the Company’s estimated proved reserves increased 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).
Year Ended December 31, 2012
Extensions, discoveries and other additions were primarily due to the success the Company's Oklahoma, Texas and Gulf Coast drilling programs. The Company added approximately 27 Bcfe of proved reserves in Oklahoma, 9 Bcfe from the La Cantera discovery in the Gulf Coast and 27 Bcfe in the Carthage Field in Texas from horizontal drilling in the Cotton Valley. Revisions of previous estimates were primarily a result of the significant decrease in the historical 12-month average price per Mcf of natural gas used to calculate estimated proved reserves, which was $2.20 per Mcf at December 31, 2012 as compared to $3.34 per Mcf at December 31, 2011. Sale of reserves in place primarily related to the divestiture of the Company's non-operated Arkansas assets.
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,
	2014				2013 (1)				2012 (1)
Future cash flows	$	1,711,404			$	1,243,627			$	728,878
Future production costs	(372,690		)		(295,666		)		(215,195		)
Future development costs	(244,784		)		(185,188		)		(110,825		)
Future income taxes	(121,192		)		(37,404		)		(9,642		)
Future net cash flows	972,738				725,369				393,216
10% annual discount	(424,176		)		(274,189		)		(162,393		)
Standardized measure of discounted future net cash flows	$	548,562			$	451,180			$	230,823
Changes in Standardized Measure
	Year Ended December 31,
	2014				2013 (1)				2012 (1)
Standardized measure at beginning of year	$	451,180			$	230,823			$	303,881
Sales and transfers of oil and gas produced, net of production costs	(173,540		)		(134,184		)		(92,562		)
Changes in price, net of future production costs	37,204				55,601				(140,230		)
Extensions and discoveries, net of future production and development costs	237,290				70,181				104,066
Changes in estimated future development costs, net of development costs incurred during this period	11,094				(25,389		)		77,188
Revisions of quantity estimates	25,591				58,508				(62,159		)
Accretion of discount	47,130				23,776				34,137
Net change in income taxes	(32,034		)		(13,182		)		30,559
Purchase of reserves in place	—				191,964				—
Sale of reserves in place	(7,240		)		(411		)		(8,186		)
Changes in production rates (timing) and other	(48,113		)		(6,507		)		(15,871		)
Net increase (decrease) in standardized measure	97,382				220,357				(73,058		)
Standardized measure at end of year	$	548,562			$	451,180			$	230,823
(1) The table above includes certain adjustments to previously disclosed estimated proved reserves as of December 31, 2013 and 2012. Specifically, as of December 31, 2014, the Company determined that it should have reflected additional downward revisions to certain of its proved undeveloped reserves totaling 5,088 MMcfe and 5,817 MMcfe as of December 31, 2013 and 2012, respectively. The table above reflects such adjustments of previous estimates for the years ended December 31, 2013 and 2012, respectively. The above adjustments had no material impact on the Company's financial statements for the years ended December 31, 2013 and 2012.
The historical twelve-month average prices of oil, gas and natural gas liquids used in determining standardized measure were:
	2014			2013			2012
Oil, $/Bbl	$96.45			$106.19			$102.81
Ngls, $/Mcfe	4.11			5.1			6.07
Natural Gas, $/Mcf	3.8			3.11			2.2

Summarized_Quarterly_Financial

Summarized Quarterly Financial Information—Unaudited	12 Months Ended
	Dec. 31, 2014
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
	2014:00:00
	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	$	0.03
	Diluted	$	0.15	$	0.15	$	0.07	$	0.03
	2013:00:00
	Revenues	$	35,976	$	38,076	$	55,578	$	53,174
	Income from operations	4,236		4,109		1,687		4,370
	Income available to common stockholders	2,607		3,662		383		2,291
	Earnings per share:
	Basic	$	0.04	$	0.06	$	0.01	$	0.04
	Diluted	$	0.04	$	0.06	$	0.01	$	0.04

Organization_and_Summary_of_Si1

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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 should be 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
	During 2006, the Company acquired a gas gathering system used in the transportation of natural gas. The costs related to this system are depreciated on a straight line basis over the estimated remaining useful life, generally 14 years. The costs related to other furniture and fixtures are depreciated on a straight line basis over estimated useful lives ranging from 3-8 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	Certain 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	The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas and OPIS Mt. Bellevue pricing for natural gas liquids. 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 and OPIS Mt. Bellevue 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 and OPIS Mt. Bellevue prices at which the hedges will be settled. At December 31, 2014, the Company’s derivative instruments were designated as effective cash flow hedges. See Note 7 for further discussion of the Company’s derivative 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 income statement as derivative income (expense). The Company does not offset fair value amounts recognized for 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.  The standard is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years.  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.  We are currently evaluating the effect that this new standard will have on our consolidated financial statements and related disclosures, however, we do not expect the adoption of the standard will have a material impact on our results of operations, financial position, or related disclosures.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of significant concentration risk	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,
			2014		2013		2012
	Shell Trading Co.		30	%	35	%	30	%
	Laclede Energy		24	%	14	%	17	%
	Unimark, LLC		14	%	14	%	(a)
	JP Morgan Ventures Energy		(a)		(a)		12	%
	(a)	Less than 10 percent

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
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 and 2012 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				2012
	Revenues	$	215,666			$	187,104
	Income (Loss) from Operations	19,858				(135,406		)
	Net Income (Loss) available to common stockholders	14,399				(142,181		)
	Basic Earnings (loss) per Share	$	0.22			$	(2.28	)
	Diluted Earnings (loss) per Share	$	0.22			$	(2.28	)

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014	Income (Numerator)			Shares	Per
					(Denominator)	Share Amount
	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
					(Denominator)	Share Amount
	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
	For the Year Ended December 31, 2012	Loss			Shares	Per
		(Numerator)			(Denominator)	Share Amount
	BASIC EPS
	Net loss available to common stockholders	$	(137,218	)	62,459	$	(2.20	)
	Effect of dilutive securities:
	Stock options	—			—
	Restricted stock	—			—
	DILUTED EPS	$	(137,218	)	62,459	$	(2.20	)

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012 is as follows (in thousands):
			Year Ended December 31,
			2014				2013			2012
	Stock options:
	Incentive Stock Options		$	573			$	310		$	786
	Non-Qualified Stock Options		171				222			660
	Restricted stock		4,504				3,684			5,464
	Restricted stock units		3,094				1,611			277
	Share-based compensation		$	8,342			$	5,827		$	7,187
Schedule of stock option valuation assumptions	The following table outlines the assumptions used in computing the fair value of stock options granted during 2014, 2013 and 2012:
			Years Ended December 31,
			2014		2013		2012
	Dividend yield		—%		—%		—%
	Expected volatility		79.4% - 80.0%		79.6% - 79.8%		79.2% - 79.6%
	Risk-free rate		1.81% - 2.015%		0.9% - 1.815%		0.8% - 1.1%
	Expected term		6 years		6 years		6 years
	Forfeiture rate		5.00%		5.00%		5.00%
	Stock options granted (1)		69,434		395,642		125,487
	Wgtd. avg. grant date fair value per share		$2.84		$2.91		$3.71
	Fair value of grants (1)		$197,000		$1,150,000		$465,000
	-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, 2014:
			Number of			Wgtd. Avg.			Wgtd. Avg.		Aggregate
			Options			Exercise  Price			Remaining  Life		Intrinsic  Value
											(000’s)
	Outstanding at beginning of year		1,892,493			$	5.67
	Granted		69,434			4.13
	Expired/cancelled/forfeited		(156,724	)		5.6
	Exercised		(287,499	)		3.34
	Outstanding at end of year		1,517,704			6.05			6.0 years		$	—
	Options exercisable at end of year		1,172,400			$	6.58		5.3 years		$	—
	Options expected to vest		328,039			4.27			8.6 years		$	—
Schedule of stock option plans, by exercise price range	The following table summarizes information regarding stock options outstanding at December 31, 2014:
	Range of		Options			Wgtd. Avg.		Wgtd. Avg.	Options			Wgtd. Avg.
	Exercise		Outstanding			Remaining		Exercise	Exercisable			Exercise
	Price		12/31/14			Contractual Life		Price	12/31/14			Price
	$2.24—$4.48		407,255			8.9 years		$4.14	115,945			$4.18
	$4.48—$6.72		355,820			4.0 years		$5.63	301,826			$5.73
	$6.72—$8.96		744,629			5.5 years		$7.25	744,629			$7.25
	$8.96—$11.20		10,000			1.1 years		$9.99	10,000			$9.99
			1,517,704			6.0 years		$6.05	1,172,400			$6.58
Schedule of restricted stock units activity	As of December 31, 2014, the Company had a liability for RSUs outstanding and expected to vest in the amount of $1.4 million.
	The following table details RSU activity during the year ended December 31, 2014:
		Number of Shares
	Outstanding at beginning of year	1,273,417
	Granted	669,469
	Expired/Cancelled/Forfeited	(66,849	)
	Vested/Paid	(496,776	)
	Outstanding at December 31, 2014	1,379,261
	The following table details restricted stock activity during the year ended December 31, 2014:
			Number of			Wgtd. Avg.
			Shares			Fair Value  per
						Share
	Outstanding at beginning of year		1,926,451			$	4.88
	Granted		1,599,750			4.32
	Expired/cancelled/forfeited		(135,861	)		5.01
	Lapse of restrictions		(962,138	)		5.22
	Outstanding at December 31, 2014		2,428,202			$	4.37

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013
	Asset retirement obligation, beginning of period	$	48,536		$	27,260
	Liabilities assumed	—			15,319
	Liabilities incurred	756			498
	Liabilities settled	(3,623		)	(3,335		)
	Accretion expense	2,958			1,753
	Revisions in estimated cash flows	6,343			7,041
	Asset retirement obligation, end of period	54,970			48,536
	Less: current portion of asset retirement obligation	(2,756		)	(3,113		)
	Long-term asset retirement obligation	$	52,214		$	45,423

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Oil and gas contracts	As of December 31, 2014, the Company had entered into the following gas hedge contracts:
	Production Period		Instrument Type		Daily Volumes		Weighted Average Price
	Natural Gas:
	2015		Swap		30,000 Mmbtu		$3.82
	At December 31, 2014, the Company had recognized an asset of approximately $8.6 million related to the estimated fair value of these derivative contracts. Based on estimated future commodity prices as of December 31, 2014, the Company would realize a $5.4 million gain, net of taxes, during the next 12 months. These gains are expected to be reclassified to oil and gas sales based on the schedule of volumes stipulated in the derivative contracts.
	During January and February 2015, the Company entered into the following additional derivative contracts accounted for as a cash flow hedges:
	Production Period		Instrument Type		Daily Volumes		Weighted Average Price
	Natural Gas:
	February - December 2015		Swap		10,000 Mmbtu		$2.93
	July 2015 - June 2016		Swap		10,000 Mmbtu		$3.22
	March 2015 - December 2015		Swap		15,000 Mmbtu		$2.99
	Crude Oil:
	February - December 2015		Swap (LLS)		250 Bbls		$54.00
	March 2015 - December 2015		Swap (LLS)		250 Bbls		$59.35
	Propane:
	March 2015 - December 2015		Swap		250 Bbls		$25.62
	LLS - Louisiana Light Sweet
Effect of Cash Flow Hedges on the Consolidated Balance Sheet	Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2014 and December 31, 2013:
		Commodity Derivatives
	Period	Balance Sheet	Fair Value
		Location
	December 31, 2014	Derivative asset	$	8,631
	December 31, 2013	Derivative asset	$	521
	December 31, 2013	Derivative liability	$	(1,617	)
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, 2014, 2013 and 2012:
	Instrument	Amount of Gain (Loss)				Location of		Amount of Gain (Loss) Reclassified into
		Recognized in Other				Gain Reclassified		Income
		Comprehensive Income				into Income
	Commodity Derivatives at December 31, 2014	$	6,516			Oil and gas sales		$	(3,044	)
	Commodity Derivatives at December 31, 2013	$	(1,617	)		Oil and gas sales		$	927
	Commodity Derivatives at December 31, 2012	$	(3,510	)		Oil and gas sales		$	9,097
Effect of Non-designated Derivative Instruments	Effect of Non-designated Derivative Instrument on the Consolidated Statement of Operations for the years ended December 31, 2013 and 2012:
	Instrument	Amount of Gain (Loss)
		Recognized in Derivative
		Income (Expense)
	Commodity Derivatives at December 31, 2013	$	233
	Commodity Derivatives at December 31, 2012	$	(233	)

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and December 31, 2013 (in thousands):
		Fair Value Measurements Using
	Instrument	Quoted Prices		Significant Other			Significant
		in Active		Observable			Unobservable
		Markets (Level 1)		Inputs (Level 2)			Inputs (Level 3)
	Commodity Derivatives:
	At December 31, 2014	$	—	$	8,631		$	—
	At December 31, 2013	$	—	$	(1,096	)	$	—

Other_Comprehensive_Income_Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2013 (in thousands):
		Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
	Balance as of December 31, 2012	$	521		$	—		$	521
	Other comprehensive loss before reclassifications:
	Change in fair value of derivatives	(999		)				(999		)
	Income tax effect	372			(408		)	(36		)
	Net of tax	(627		)	(408		)	(1,035		)
	Amounts reclassified from accumulated other comprehensive income:
	Oil and gas sales	(927		)				(927		)
	Income tax effect	345			—			345
	Net of tax	(582		)	—			(582		)
	Net other comprehensive loss	(1,209		)	(408		)	(1,617		)
	Balance as of December 31, 2013	$	(688	)	$	(408	)	$	(1,096	)
	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 loss 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 loss	6,108			408			6,516
	Balance as of December 31, 2014	$	5,420		$	—		$	5,420

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Deferred Taxes	An analysis of the Company’s deferred taxes follows (amounts in thousands):
		December 31,
		2014			2013			2012
	Net operating loss carryforwards	$	17,705		$	21,810		$	16,641
	Percentage depletion carryforward	10,206			8,645			7,317
	Alternative minimum tax credits	784			784			784
	Contributions carryforward and other	241			189			156
	Temporary differences:
	Oil and gas properties	(15,439		)	(7,248		)	12,575
	Asset retirement obligation	20,449			18,056			10,141
	Derivatives	(3,211		)	408			(222		)
	Share-based compensation	2,560			2,887			3,474
	Valuation allowance	(33,295		)	(45,531		)	(50,866		)
	Deferred taxes	$	—		$	—		$	—
Income Tax Reconciliation	Income tax expense (benefit) for each of the years ended December 31, 2014, 2013 and 2012 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,
		2014			2013			2012
	Amount computed using the statutory rate	$	9,887		$	5,041		$	(45,655	)
	Increase (reduction) in taxes resulting from:
	State & local taxes	904			317			(2,870		)
	Percentage depletion carryforward	(1,564		)	(1,323		)	(1,309		)
	Non-deductible stock option expense (1)	213			115			292
	Share-based compensation (2)	90			780			9
	Other	(643		)	1,132			303
	Change in valuation allowance	(11,828		)	(5,742		)	50,866
	Income tax expense (benefit)	$	(2,941	)	$	320		$	1,636
	-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, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Lease Commitments	Future minimum lease commitments as of December 31, 2014 under these operating leases are as follows (in thousands):
	2015	$	1,480
	2016	1,418
	2017	1,317
	2018	416
	2019	401
	Thereafter	1,631
		$	6,663

Supplementary_Information_on_O1

Supplementary Information on Oil and Gas Operations—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Costs Incurred in Oil and Gas Property Acquisition	Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
	(amounts in thousands)
		For the Year-Ended December 31,
		2014				2013				2012
	Acquisition costs:
	Proved (1)	$	3,064			$	177,880			$	352
	Unproved (1)	39,164				35,008				15,677
	Divestitures—unproved (2)	(3,298		)		(487		)		(8,889		)
	Exploration costs:
	Proved	67,297				34,344				72,361
	Unproved	13,515				20,112				18,033
	Development costs	55,722				41,328				18,740
	Capitalized general and administrative and interest costs	22,121				19,911				18,961
	Total costs incurred	$	197,585			$	328,096			$	135,235
Rollforward of Accumulated Depreciation, Depletion and Amortization of Oil and Gas Producing Activities	Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
	(amounts in thousands)
		For the Year-Ended December 31,
		2014				2013				2012
	Acquisition costs:
	Proved (1)	$	3,064			$	177,880			$	352
	Unproved (1)	39,164				35,008				15,677
	Divestitures—unproved (2)	(3,298		)		(487		)		(8,889		)
	Exploration costs:
	Proved	67,297				34,344				72,361
	Unproved	13,515				20,112				18,033
	Development costs	55,722				41,328				18,740
	Capitalized general and administrative and interest costs	22,121				19,911				18,961
	Total costs incurred	$	197,585			$	328,096			$	135,235
		For the Year-Ended December 31,
		2014				2013				2012
	Accumulated depreciation, depletion and amortization (DD&A)
	Balance, beginning of year	$	(1,553,044	)		$	(1,472,244	)		$	(1,265,603	)
	Provision for DD&A	(86,406		)		(69,357		)		(59,496		)
	Ceiling test writedown	—				—				(137,100		)
	Sale of proved properties and other (3)	(8,610		)		(11,443		)		(10,045		)
	Balance, end of year	$	(1,648,060	)		$	(1,553,044	)		$	(1,472,244	)
	DD&A per Mcfe	$	1.99			$	1.82			$	1.75
	-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 2012, the Company sold an additional portion of its Mississippian Lime acreage for $6.1 million.
	-3	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. During 2012, the Company sold its non-operated Arkansas assets for a net cash purchase price of $8.5 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
		in			in			in			Reserves
		MBbls			MMcfe			MMcf			in MMcfe
	Proved reserves as of December 31, 2011	1,395			15,111			241,926			265,407
	Revisions of previous estimates (1)	195			(1,952	)		(56,780	)		(57,561	)
	Extensions, discoveries and other additions	647			14,572			46,390			64,844
	Sale of reserves in place	(81	)		—			(15,806	)		(16,292	)
	Production	(521	)		(3,365	)		(27,466	)		(33,957	)
	Proved reserves as of December 31, 2012	1,635			24,366			188,264			222,441
	Revisions of previous estimates (1)	(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
	Purchase of producing properties	—			—			—			—
	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
	Proved developed reserves
	As of December 31, 2012	1,225			20,608			140,307			168,265
	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
	Proved undeveloped reserves
	As of December 31, 2012 (1)	410			3,758			47,957			54,176
	As of December 31, 2013 (1)	322			5,257			86,381			93,571
	As of December 31, 2014	348			30,914			126,458			159,460
	(1) The table above includes certain adjustments to previously disclosed estimated proved reserves as of December 31, 2013 and 2012. Specifically, as of December 31, 2014, the Company determined that it should have reflected additional downward revisions to certain of its proved undeveloped reserves totaling 5,088 MMcfe and 5,817 MMcfe as of December 31, 2013 and 2012, respectively. The table above reflects such adjustments of previous estimates for the years ended December 31, 2013 and 2012, respectively. The above adjustments had no material impact on the Company's financial statements for the years ended December 31, 2013 and 2012.
Standardized measure of discounted future cash flows	Standardized Measure
		December 31,
		2014				2013 (1)				2012 (1)
	Future cash flows	$	1,711,404			$	1,243,627			$	728,878
	Future production costs	(372,690		)		(295,666		)		(215,195		)
	Future development costs	(244,784		)		(185,188		)		(110,825		)
	Future income taxes	(121,192		)		(37,404		)		(9,642		)
	Future net cash flows	972,738				725,369				393,216
	10% annual discount	(424,176		)		(274,189		)		(162,393		)
	Standardized measure of discounted future net cash flows	$	548,562			$	451,180			$	230,823
Schedule of changes in standardized measure of discounted future net cash flows	Changes in Standardized Measure
		Year Ended December 31,
		2014				2013 (1)				2012 (1)
	Standardized measure at beginning of year	$	451,180			$	230,823			$	303,881
	Sales and transfers of oil and gas produced, net of production costs	(173,540		)		(134,184		)		(92,562		)
	Changes in price, net of future production costs	37,204				55,601				(140,230		)
	Extensions and discoveries, net of future production and development costs	237,290				70,181				104,066
	Changes in estimated future development costs, net of development costs incurred during this period	11,094				(25,389		)		77,188
	Revisions of quantity estimates	25,591				58,508				(62,159		)
	Accretion of discount	47,130				23,776				34,137
	Net change in income taxes	(32,034		)		(13,182		)		30,559
	Purchase of reserves in place	—				191,964				—
	Sale of reserves in place	(7,240		)		(411		)		(8,186		)
	Changes in production rates (timing) and other	(48,113		)		(6,507		)		(15,871		)
	Net increase (decrease) in standardized measure	97,382				220,357				(73,058		)
	Standardized measure at end of year	$	548,562			$	451,180			$	230,823
	(1) The table above includes certain adjustments to previously disclosed estimated proved reserves as of December 31, 2013 and 2012. Specifically, as of December 31, 2014, the Company determined that it should have reflected additional downward revisions to certain of its proved undeveloped reserves totaling 5,088 MMcfe and 5,817 MMcfe as of December 31, 2013 and 2012, respectively. The table above reflects such adjustments of previous estimates for the years ended December 31, 2013 and 2012, respectively. The above adjustments had no material impact on the Company's financial statements for the years ended December 31, 2013 and 2012.
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:
		2014			2013			2012
	Oil, $/Bbl	$96.45			$106.19			$102.81
	Ngls, $/Mcfe	4.11			5.1			6.07
	Natural Gas, $/Mcf	3.8			3.11			2.2

Summarized_Quarterly_Financial1

Summarized Quarterly Financial Information—Unaudited (Tables)	12 Months Ended
	Dec. 31, 2014
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
	2014:00:00
	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	$	0.03
	Diluted	$	0.15	$	0.15	$	0.07	$	0.03
	2013:00:00
	Revenues	$	35,976	$	38,076	$	55,578	$	53,174
	Income from operations	4,236		4,109		1,687		4,370
	Income available to common stockholders	2,607		3,662		383		2,291
	Earnings per share:
	Basic	$	0.04	$	0.06	$	0.01	$	0.04
	Diluted	$	0.04	$	0.06	$	0.01	$	0.04

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies - PPE (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Allowance for doubtful accounts	100,000	$0
Other current assets	5,566,000	8,132,000
Deferred finance costs	5,500,000	7,400,000
Gas gathering system
Property, Plant and Equipment [Line Items]
Useful life (in years)	14 years
Well equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful life (in years)	3 years
Well equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful life (in years)	8 years
Oklahoma
Property, Plant and Equipment [Line Items]
Other current assets	900,000	$3,100,000
Oklahoma | Building
Property, Plant and Equipment [Line Items]
Useful life (in years)	39 years

Organization_and_Summary_of_Si4

Organization and Summary of Significant Accounting Policies Organization and Summary of Significant Accounting Policies - Revenues (Details) (Oil and Gas Revenue [Member], Customer Concentration Risk [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Shell Trading Co.
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	30.00%	35.00%	30.00%
Laclede Energy
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	24.00%	14.00%	17.00%
Unimark, LLC
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	14.00%	14.00%
JP Morgan Ventures Energy
Concentration Risk [Line Items]
Net oil and gas revenues (percent)			12.00%

Organization_and_Summary_of_Si5

Organization and Summary of Significant Accounting Policies - Fair Value of Financial Instruments (Details) (Designated as Hedging Instrument, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	($3,000)	$900	$9,100

Convertible_Preferred_Stock_De

Convertible Preferred Stock (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Rate
Convertible Preferred Stock (Textual) [Abstract]
Preferred stock, outstanding shares	1,495,000	1,495,000
Series B cumulative convertible perpetual preferred stock interest rate	6.88%
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.
Conversion rate numerator for Preferred Stock	$50

Acquisitions_Details

Acquisitions (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 03, 2013	Jun. 30, 2014
					sqmi
					acre
Business Acquisition [Line Items]
Payments of financing costs	$253,000	$320,000	$42,000
Accrued acquisition costs	17,690,000	0
10% Senior Notes
Business Acquisition [Line Items]
Principal amount	150,000,000
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				16
Number of platforms purchased				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%			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
Working interest (as a percent)					37.00%
Number of acres acquired					30,000
Number of square miles					200
Cash funding for future drilling					14,000,000
Accrued acquisition costs, cash	7,000,000
Accrued acquisition costs, funding for drilling	10,700,000
Accrued acquisition costs	$17,700,000

Acquisitions_Schedule_of_Asset

Acquisitions (Schedule of Assets Acquired and Liabilities Assumed) (Details) (Gulf of Mexico Acquisition, USD $)	Jul. 03, 2013
In Thousands, unless otherwise specified
Gulf of Mexico Acquisition
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_Pro_Forma_Details

Acquisitions (Pro Forma) (Details) (Gulf of Mexico Acquisition, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Gulf of Mexico Acquisition
Business Acquisition [Line Items]
Revenues	$215,666	$187,104
Income (Loss) from Operations	19,858	-135,406
Net Income (Loss) available to common stockholders	$14,399	($142,181)
Basic Earnings (loss) per Share (in dollars per share)	$0.22	($2.28)
Diluted Earnings (loss) per Share (in dollars per share)	$0.22	($2.28)

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
A reconciliation between basic and diluted earnings per share computations
Net income (loss) available to common stockholders	$1,745	$4,671	$9,592	$10,043	$2,291	$383	$3,662	$2,607	$26,051	$8,943	($137,218)
Net loss available to common stockholders (in shares)									64,204	63,054	62,459
Attributable to participating securities									-855	-257
Net income or loss available to common stockholders, Loss (excluding income attributable to participating securities)									25,196	8,686
Net loss available to common stockholders (in dollars per share)	$0.03	$0.07	$0.15	$0.15	$0.04	$0.01	$0.06	$0.04	$0.39	$0.14	($2.20)
Stock options, effect of dilutive securities, (in shares)									21	154
Attributable to participating securities									-854	-256
Restricted stock, effect of dilutive securities (in shares)									0	0	0
DILUTED EPS, Loss									$25,197	$8,687	($137,218)
DILUTED EPS (in shares)									64,225	63,208	62,459
DILUTED EPS, Per Share Amount (in dollars per share)	$0.03	$0.07	$0.15	$0.15	$0.04	$0.01	$0.06	$0.04	$0.39	$0.14	($2.20)

Earnings_Per_Share_Details_Tex

Earnings Per Share (Details Textual)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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)	1	1.2	0.9

ShareBased_Compensation_Share_

Share-Based Compensation - Share based Compensation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of share-based compensation
Share based compensation	$8,342	$5,827	$7,187
Incentive Stock Options
Summary of share-based compensation
Share based compensation	573	310	786
Non-Qualified Stock Options
Summary of share-based compensation
Share based compensation	171	222	660
Restricted stock
Summary of share-based compensation
Share based compensation	4,504	3,684	5,464
Restricted stock units
Summary of share-based compensation
Share based compensation	$3,094	$1,611	$277

ShareBased_Compensation_Narrat

Share-Based Compensation - Narrative (Details) (USD $)	12 Months Ended			1 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Tax benefit from compensation expense	$2.30	$1.80	$2.30
Total compensation cost not yet recognized	7.6
Period for recognition (in years)	3 years
Fair value of stock options that vested during period	1	0.8	1.7
Restricted stock
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)	1,599,750
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%	5.00%
Exercise price percent of fair value at grant date	100.00%
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	669,469
Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual vesting percentage	33.33%
Granted (in shares)				243,067
Evaluation period (in days)	20 days
Number of peer group companies	12
Prior to 2011 | Restricted stock
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-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	$1.50	$0.80	$0.10

ShareBased_Compensation_Fair_V

Share-Based Compensation - Fair Value Assumption (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Stock options granted (shares)	69,434
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%	0.00%
Expected volatility, minimum (as a percent)	79.40%	79.60%	79.20%
Expected volatility, maximum (as a percent)	80.00%	79.80%	79.60%
Risk-free rate, minimum (as a percent)	1.81%	0.90%	0.80%
Risk-free rate, maximum (as a percent)	2.02%	1.82%	1.10%
Expected term (in years)	6 years	6 years	6 years
Forfeiture rate (as a percent)	5.00%	5.00%	5.00%
Stock options granted (shares)	69,434	395,642	125,487
Weighted average grant date fair value (usd per share)	$2.84	$2.91	$3.71
Fair value of grants	$197	$1,150	$465

ShareBased_Compensation_Activi

Share-Based Compensation - Activity (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014
Number of Options (in shares)
Outstanding at beginning of year	1,892,493
Granted	69,434
Expired/cancelled/forfeited	-156,724
Exercised	-287,499
Outstanding at end of year	1,517,704
Wgtd. Avg. Exercise Price (in dollars per share)
Outstanding at beginning of year	$5.67
Granted	$4.13
Expired/cancelled/forfeited	$5.60
Exercised	$3.34
Outstanding at end of year	$6.05
Additional Disclosures
Options exercisable at end of year	1,172,400
Options expected to vest	328,039
Options exercisable at end of year (usd per share)	$6.58
Options expected to vest (usd per share)	$4.27
Outstanding, remaining contractual term (in years)	6 years
Exercisable, remaining contractual term (in years)	5 years 3 months 18 days
Vested and expected to vest, remaining contractual term (in years)	8 years 7 months 6 days
Outstanding, intrinsic value	$0
Exercisable, intrinsic value	0
Vested and expected to vest, intrinsic value	$0

ShareBased_Compensation_Exerci

Share-Based Compensation - Exercise Prices (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding at end of year (in shares)	1,517,704	1,892,493
Outstanding, remaining contractual term (in years)	6 years
Outstanding at end of year	$6.05	$5.67
Options exercisable at end of year	1,172,400
Options exercisable (usd per share)	$6.58
$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)	407,255
Outstanding, remaining contractual term (in years)	8 years 10 months 24 days
Outstanding at end of year	$4.14
Options exercisable at end of year	115,945
Options exercisable (usd per share)	$4.18
$4.48—$6.72
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	$4.48
Exercise price range, upper range limit	$6.72
Outstanding at end of year (in shares)	355,820
Outstanding, remaining contractual term (in years)	4 years
Outstanding at end of year	$5.63
Options exercisable at end of year	301,826
Options exercisable (usd per share)	$5.73
$6.72—$8.96
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	$6.72
Exercise price range, upper range limit	$8.96
Outstanding at end of year (in shares)	744,629
Outstanding, remaining contractual term (in years)	5 years 6 months
Outstanding at end of year	$7.25
Options exercisable at end of year	744,629
Options exercisable (usd per share)	$7.25
$8.96—$11.20
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	$8.96
Exercise price range, upper range limit	$11.20
Outstanding at end of year (in shares)	10,000
Outstanding, remaining contractual term (in years)	1 year 1 month 6 days
Outstanding at end of year	$9.99
Options exercisable at end of year	10,000
Options exercisable (usd per share)	$9.99

ShareBased_Compensation_Restri

Share-Based Compensation - Restricted Stock (Details) (Restricted stock, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted stock
Number of Shares (in shares)
Outstanding at beginning of year	1,926,451
Granted	1,599,750
Expired/cancelled/forfeited	-135,861
Lapse of restrictions	-962,138
Outstanding at end of year	2,428,202	1,926,451
Wgtd. Avg. Fair Value per Share (in dollars per share)
Outstanding at beginning of year	$4.88
Granted	$4.32	$4.18	$5.24
Expired/cancelled/forfeited	$5.01
Lapse of restrictions	$5.22
Outstanding at end of year	$4.37	$4.88
Total value of stock that vested	$5	$5.40	$4.70
Additional Information
Weighted average remaining life (in years)	2 years
Value of restricted stock outstanding	$9.40

ShareBased_Compensation_ShareB

Share-Based Compensation Share-Based Compensation - Restricted Stock Units (Details) (Restricted stock units, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total value of stock that vested	$2
Liability for RSUs outstanding and expected to vest	1,400,000
Number of Shares (in shares)
Outstanding at beginning of year	1,273,417
Granted	669,469
Expired/cancelled/forfeited	-66,849
Vested/Paid	-496,776
Outstanding at end of year	1,379,261

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$48,536	$27,260
Liabilities assumed	0	15,319
Liabilities incurred	756	498
Liabilities settled	-3,623	-3,335
Accretion expense	2,958	1,753
Revisions in estimated cash flows	6,343	7,041
Asset retirement obligation, end of period	54,970	48,536
Less: current portion of asset retirement obligation	-2,756	-3,113
Long-term asset retirement obligation	$52,214	$45,423

Derivative_Instruments_Details

Derivative Instruments (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Natural Gas | 2015 | Swap
Oil and gas contracts
Weighted Average Price	$3.82
Natural Gas | February - December 2015 | Swap
Oil and gas contracts
Daily Volumes	10,000
Weighted Average Price	$2.93
Natural Gas | July 2015 - June 2016 | Swap
Oil and gas contracts
Daily Volumes	10,000
Weighted Average Price	$3.22
Natural Gas | March 2015 - December 2015 | Swap
Oil and gas contracts
Daily Volumes	15,000
Weighted Average Price	$2.99
Crude Oil: | February - December 2015 | Swap (LLS)
Oil and gas contracts
Daily Volumes	250
Weighted Average Price	$54
Crude Oil: | March 2015 - December 2015 | Swap (LLS)
Oil and gas contracts
Daily Volumes	250
Weighted Average Price	$59.35
Propane: | March 2015 - December 2015 | Swap
Oil and gas contracts
Daily Volumes	250
Weighted Average Price	$25.62

Derivative_Instruments_Details1

Derivative Instruments (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Asset fair value	$8,600
Designated as Hedging Instrument | Commodity Contract | Derivative asset
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Asset fair value	8,631	521
Designated as Hedging Instrument | Commodity Contract | Derivative liability
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Liability fair value		($1,617)

Derivative_Instruments_Details2

Derivative Instruments (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effect of Derivative Instruments on the Consolidated Statement of Operations
Amount of Gain (Loss) Recognized in Other Comprehensive Income	$6,516	($1,617)	($3,510)
Designated as Hedging Instrument
Effect of Derivative Instruments on the Consolidated Statement of Operations
Amount of Gain (Loss) Recognized in Other Comprehensive Income	6,516	-1,617	-3,510
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	($3,044)	$927	$9,097

Derivative_Instruments_Details3

Derivative Instruments (Details 4) (Not Designated as Hedging Instrument, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Not Designated as Hedging Instrument
Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations
Amount of Gain (Loss) Recognized in Derivative Income (Expense)	$233	($233)

Derivative_Instruments_Details4

Derivative Instruments (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments (Textual) [Abstract]
Asset fair value	$8,600,000
Realization of gain, net of taxes	5,400,000
Gas hedges
Derivative Instruments (Textual) [Abstract]
Net settlement of hedges	-4,237,000	1,098,000	6,846,000
NGL hedges
Derivative Instruments (Textual) [Abstract]
Net settlement of hedges	296,000	61,000	722,000
Crude Oil
Derivative Instruments (Textual) [Abstract]
Net settlement of hedges	$897,000	($232,000)	$1,529,000

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
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	8,631,000	-1,096,000
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	$301,000,000	$364,000,000

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Jul. 03, 2013	Sep. 29, 2014	Sep. 28, 2014	Dec. 31, 2013	Aug. 19, 2010	Feb. 28, 2015
	Rate						Rate
Long-Term Debt (Textual) [Abstract]
Adjusted interest on notes payable	$11,700,000
Revolving Credit facility	300,000,000
Current borrowing base			220,000,000	200,000,000
Aggregate commitments of the lenders	170,000,000
At least secured percentage value of oil and gas properties	80.00%
Accrued in connection with the interest payment	5,000,000
Agreement bear interest at the alternate base rate	Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% 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 plus 1%.
Bank debt	75,000,000				75,000,000
Maximum
Long-Term Debt (Textual) [Abstract]
Commitment fees on a sliding scale (as a percent)	0.50%
Repurchase Company's common stock	10,000,000
Maximum ratio of total debt to EBITDAX	3.5
Minimum
Long-Term Debt (Textual) [Abstract]
Commitment fees on a sliding scale (as a percent)	0.38%
Maximum ratio of total debt to EBITDAX	1,000
Borrower's Liquidity (as a percent)	20.00%
Letters of credit
Long-Term Debt (Textual) [Abstract]
Revolving Credit facility	25,000,000
Federal Funds Effective Rate
Long-Term Debt (Textual) [Abstract]
Adjusted LIBO rate (as a percent)	0.50%
Alternate Base Rate | Maximum
Long-Term Debt (Textual) [Abstract]
Adjusted LIBO rate (as a percent)	1.50%
Alternate Base Rate | Minimum
Long-Term Debt (Textual) [Abstract]
Adjusted LIBO rate (as a percent)	0.50%
Adjusted London Inter Bank Offer Rate
Long-Term Debt (Textual) [Abstract]
Adjusted LIBO rate (as a percent)	1.00%
Adjusted London Inter Bank Offer Rate | Maximum
Long-Term Debt (Textual) [Abstract]
Adjusted LIBO rate (as a percent)	2.50%
Adjusted London Inter Bank Offer Rate | Minimum
Long-Term Debt (Textual) [Abstract]
Adjusted LIBO rate (as a percent)	1.50%
10% Senior Notes | Senior Notes
Long-Term Debt (Textual) [Abstract]
Principal amount		200,000,000				150,000,000
Gulf of Mexico Acquisition | 10% Senior Notes
Long-Term Debt (Textual) [Abstract]
Purchase price		$188,800,000
Subsequent Event | Maximum
Long-Term Debt (Textual) [Abstract]
Maximum ratio of total debt to EBITDAX							2.25
Maximum ratio of EBITDAX to cash interest expense							2

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$5,000
Goodson
Related Party Transaction [Line Items]
Payments of distributions to related parties	-80,000	-92,000	-104,000
Related expenses related to transactions with related party	18,200	0	16,900
Green
Related Party Transaction [Line Items]
Payments of distributions to related parties	-116,000	-269,000	-387,000
Nordberg
Related Party Transaction [Line Items]
Payments of distributions to related parties		-200
Due to Affiliate			$100

Ceiling_Test_Writedown_Details

Ceiling Test Write-down (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Ceiling Test (Textual) [Abstract]
Ceiling test write-down	$0	$0	$137,100,000
Decrease in ceiling test write-down			($2,200,000)
Mcf of natural gas
Ceiling Test (Textual) [Abstract]
Average sales prices			2.21
Barrel of oil
Ceiling Test (Textual) [Abstract]
Average sales prices			102.81
Mcfe of Ngl
Ceiling Test (Textual) [Abstract]
Average sales prices			6.07

Other_Comprehensive_Income_Det

Other Comprehensive Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income [Roll Forward]
Balance. beginning of period	($1,096)	$521
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	6,683	-999
Income tax effect	-2,079	-36
Net of tax	4,604	-1,035
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	3,044	-927
Income tax effect	-1,132	345
Net of tax	1,912	-582
Net other comprehensive loss	6,516	-1,617
Balance, end of period	5,420	-1,096
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income [Roll Forward]
Balance. beginning of period	-688	521
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	6,683	-999
Income tax effect	-2,487	372
Net of tax	4,196	-627
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	3,044	-927
Income tax effect	-1,132	345
Net of tax	1,912	-582
Net other comprehensive loss	6,108	-1,209
Balance, end of period	5,420	-688
Change in Valuation Allowance
Accumulated Other Comprehensive Income [Roll Forward]
Balance. beginning of period	-408	0
Other comprehensive loss before reclassifications:
Income tax effect	408	-408
Net of tax	408	-408
Amounts reclassified from accumulated other comprehensive income:
Income tax effect	0	0
Net of tax	0	0
Net other comprehensive loss	408	-408
Balance, end of period	$0	($408)

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2025
Income Taxes (Textual) [Abstract]
Income taxes at a statutory rate	35.00%	35.00%
Cumulative loss period	3 years
Deferred Tax Assets, Valuation Allowance	$33,295,000	$50,866,000	$45,531,000
Operating loss carryforwards	60,200,000
Share-based Compensation
Income Taxes (Textual) [Abstract]
Operating loss carryforwards	12,600,000
Depletion Deduction
Income Taxes (Textual) [Abstract]
Depletion deduction carryforward	29,200,000
Scenario, Forecast
Income Taxes (Textual) [Abstract]
Operating loss carryforwards				$8,700,000

Income_Taxes_Details_1_Details

Income Taxes (Details 1) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$17,705	$21,810	$16,641
Percentage depletion carryforward	10,206	8,645	7,317
Alternative minimum tax credits	784	784	784
Contributions carryforward and other	241	189	156
Oil and gas properties	-15,439	-7,248	12,575
Asset retirement obligation	20,449	18,056	10,141
Derivatives	-3,211	408	-222
Share-based compensation	2,560	2,887	3,474
Valuation allowance	-33,295	-45,531	-50,866
Deferred taxes	$0	$0	$0

Income_Taxes_Details_2_Details

Income Taxes (Details 2) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Amount computed using the statutory rate	$9,887	$5,041	($45,655)
State & local taxes	904	317	-2,870
Percentage depletion carryforward	-1,564	-1,323	-1,309
Non-deductible stock option expense	213	115	292
Share-based compensation	90	780	9
Other	-643	1,132	303
Change in valuation allowance	-11,828	-5,742	50,866
Income tax expense (benefit)	($2,941)	$320	$1,636

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2015	$1,480,000
2016	1,418,000
2017	1,317,000
2018	416,000
2019	401,000
Thereafter	1,631,000
Total	6,663,000
Operating leases rent expense	$1,600,000	$1,400,000	$1,400,000

Supplementary_Information_on_O2

Supplementary Information on Oil and Gas Operations—Unaudited - Costs Incurred (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Acquisition costs: Proved	$3,064	$177,880	$352
Acquisition costs: Unproved	39,164	35,008	15,677
Divestitures—unproved	-3,298	-487	-8,889
Exploration costs: Proved	67,297	34,344	72,361
Exploration costs: Unproved	13,515	20,112	18,033
Development costs	55,722	41,328	18,740
Capitalized general and administrative and interest costs	22,121	19,911	18,961
Total costs incurred	197,585	328,096	135,235
Movement in Accumulated Depreciation, Depletion and Amortization [Roll Forward]
Balance, beginning of year	-1,553,044	-1,472,244	-1,265,603
Provision for DD&A	-86,406	-69,357	-59,496
Ceiling test writedown	0	0	-137,100
Sale of proved properties and other	-8,610	-11,443	-10,045
Balance, end of year	($1,648,060)	($1,553,044)	($1,472,244)
DD&A per Mcfe (usd per mcfe)	1.99	1.82	1.75

Supplementary_Information_on_O3

Supplementary Information on Oil and Gas Operations—Unaudited - Investment in Oil and Gas Properties - Unaudited (Textuals) (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 03, 2013	Jun. 30, 2014
		MBbls	MBbls	acre	acre
Reserve Quantities [Line Items]
Sale of oil and gas properties	$8,610,000	$19,913,000	$837,000
Unevaluated oil and gas properties	109,100,000	98,400,000
Interest costs capitalized	10,000,000	6,600,000	7,000,000
Oil and Gas Producing Activities, Expected Period to Evaluate Existing Unevaluated Properties	3 years
Unevaluated costs expected to be evaluated in 2013	32,500,000
Proved undeveloped reserve		5,088,000	5,817,000
Mississippian Lime
Reserve Quantities [Line Items]
Sale of oil and gas properties			6,100,000
Eagle Ford
Reserve Quantities [Line Items]
Sale of oil and gas properties	9,800,000
Woodford
Reserve Quantities [Line Items]
Sale of oil and gas properties		10,400,000
Percent of saltwater disposal systems and related surface assets sold		50.00%
Wyoming
Reserve Quantities [Line Items]
Sale of oil and gas properties		1,000,000
Arkansas
Reserve Quantities [Line Items]
Sale of oil and gas properties			8,500,000
Uncompleted Wells Equipment and Facilities
Reserve Quantities [Line Items]
Unevaluated oil and gas properties	16,800,000	11,300,000
Exploratory wells drilled, unevaluated	16	19
2012
Reserve Quantities [Line Items]
Unevaluated oil and gas properties	56,300,000
Percentage of unevaluated costs capitalized in period	52.00%
2011
Reserve Quantities [Line Items]
Unevaluated oil and gas properties		21,100,000
Percentage of unevaluated costs capitalized in period		19.00%
Prior to 2011
Reserve Quantities [Line Items]
Unevaluated oil and gas properties			31,700,000
Percentage of unevaluated costs capitalized in period			29.00%
Gulf of Mexico Acquisition
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)		35,000,000
Unevaluated acres acquired				13,500
10% Senior Notes | Gulf of Mexico Acquisition
Reserve Quantities [Line Items]
Purchase price				188,800,000
Louisiana | Fleetwood Joint Venture
Reserve Quantities [Line Items]
Aggregate purchase price					24,000,000
Number of acres acquired					30,000
Purchase price					$10,000,000

Supplementary_Information_on_O4

Supplementary Information on Oil and Gas Operations—Unaudited - Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBbls	MBbls	MBbls
Proved Developed and Undeveloped Reserves [Abstract]
Proved undeveloped reserve		5,088,000	5,817,000
Oil
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance	3,031,000	-156,000	1,395,000
Revisions of previous estimates (1)	-37,000	434,000	195,000
Extensions, discoveries and other additions	475,000	1,833,000	647,000
Sale of reserves in place	0	-34,000	-81,000
Production	-229,000		-521,000
Proved reserves as of December 31, 2012	-803,000	-681,000	-1,635,000
Proved reserves ending balance	2,437,000	3,031,000	-156,000
Proved developed reserves	2,089,000	2,709,000	1,225,000
Proved undeveloped reserve	348,000	322,000	410,000
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	28,430,000	804,000	15,111,000
Revisions of previous estimates (1)	2,894,000	6,099,000	-1,952,000
Extensions, discoveries and other additions	49,990,000	1,915,000	14,572,000
Sale of reserves in place	0	0	0
Production	-334,000		-3,365,000
Proved reserves as of December 31, 2012	-7,482,000	-4,754,000	-24,366,000
Proved reserves, ending balance	73,498,000	28,430,000	804,000
Proved undeveloped reserve	42,584,000	23,173,000	20,608,000
Proved developed reserves	30,914,000	5,257,000	3,758,000
Natural Gas
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance	250,109,000	38,383,000	241,926,000
Revisions of previous estimates (1)	9,976,000	30,429,000	-56,780,000
Extensions, discoveries and other additions	82,364,000	22,274,000	46,390,000
Sale of reserves in place	0	-15,000	-15,806,000
Production	-2,396,000		-27,466,000
Proved reserves as of December 31, 2012	-31,028,000	-29,226,000	-188,264,000
Proved reserves ending balance	309,025,000	250,109,000	38,383,000
Proved developed reserves	182,567,000	163,728,000	140,307,000
Proved undeveloped reserve	126,458,000	86,381,000	47,957,000
Oil and Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	296,723,000	38,247,000	265,407,000
Revisions of previous estimates (1)	12,650,000	39,132,000	-57,561,000
Extensions, discoveries and other additions	135,205,000	35,187,000	64,844,000
Sale of reserves in place	0	-218,000	-16,292,000
Production	-4,105,000		-33,957,000
Proved reserves as of December 31, 2012	-43,325,000	-38,066,000	-222,441,000
Proved reserves, ending balance	397,148,000	296,723,000	38,247,000
Proved undeveloped reserve	237,688,000	203,152,000	168,265,000
Proved developed reserves	159,460,000	93,571,000	54,176,000

Supplementary_Information_on_O5

Supplementary Information on Oil and Gas Operations—Unaudited - Average Price and Text (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcf	MMcf	MMcf
Reserve Quantities [Line Items]
Increase in proved developed and undeveloped reserves	34.00%
Company drilling success rate	91.00%
Gross wells drilled	58
Oklahoma
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)	72,000,000	23,000,000	27,000,000
Texas
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)	46,000,000	10,000,000	27,000,000
Gulf Coast
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)	15,000,000	5,000,000	9,000,000
Oil
Reserve Quantities [Line Items]
Number of Bcfe additions	475,000	1,833,000	647,000
Consolidated oil and gas production costs per unit of production	96.45	106.19	102.81
Natural Gas Liquids
Reserve Quantities [Line Items]
Extensions, discoveries and other additions of Bcfe	49,990,000	1,915,000	14,572,000
Consolidated oil and gas production costs per unit of production	4.11	5.1	6.07
Oil and Natural Gas Reserves
Reserve Quantities [Line Items]
Extensions, discoveries and other additions of Bcfe	135,205,000	35,187,000	64,844,000
Natural Gas
Reserve Quantities [Line Items]
Number of Bcfe additions	82,364,000	22,274,000	46,390,000
Consolidated oil and gas production costs per unit of production	3.8	3.11	2.2	3.34
Gulf of Mexico Acquisition
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, increases (decreases)		35,000,000

Supplementary_Information_on_O6

Supplementary Information on Oil and Gas Operations—Unaudited - Standardized Measure (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows [Abstract]
Future cash flows	$1,711,404	$1,243,627	$728,878
Future production costs	-372,690	-295,666	-215,195
Future development costs	-244,784	-185,188	-110,825
Future income taxes	-121,192	-37,404	-9,642
Future net cash flows	972,738	725,369	393,216
10% annual discount	-424,176	-274,189	-162,393
Standardized measure of discounted future net cash flows	$548,562	$451,180	$230,823	$303,881

Supplementary_Information_on_O7

Supplementary Information on Oil and Gas Operations—Unaudited - Changes in Standardized Measure (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$451,180	$230,823	$303,881
Sales and transfers of oil and gas produced, net of production costs	-173,540	-134,184	-92,562
Changes in price, net of future production costs	37,204	55,601	-140,230
Extensions and discoveries, net of future production and development costs	237,290	70,181	104,066
Changes in estimated future development costs, net of development costs incurred during this period	11,094	-25,389	77,188
Revisions of quantity estimates	25,591	58,508	-62,159
Accretion of discount	47,130	23,776	34,137
Net change in income taxes	-32,034	-13,182	30,559
Purchase of reserves in place	0	191,964	0
Sale of reserves in place	-7,240	-411	-8,186
Changes in production rates (timing) and other	-48,113	-6,507	-15,871
Net increase (decrease) in standardized measure	97,382	220,357	-73,058
Standardized measure at end of year	$548,562	$451,180	$230,823

Summarized_Quarterly_Financial2

Summarized Quarterly Financial Information—Unaudited (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues	$47,988	$56,486	$60,581	$59,966	$53,174	$55,578	$38,076	$35,976
Income from operations	478	5,569	10,879	11,323	4,370	1,687	4,109	4,236	28,249	14,402	-130,443
Income available to common stockholders	$1,745	$4,671	$9,592	$10,043	$2,291	$383	$3,662	$2,607	$26,051	$8,943	($137,218)
Earnings per share, Basic (in usd per share)	$0.03	$0.07	$0.15	$0.15	$0.04	$0.01	$0.06	$0.04	$0.39	$0.14	($2.20)
Earnings per share, Diluted (in usd per share)	$0.03	$0.07	$0.15	$0.15	$0.04	$0.01	$0.06	$0.04	$0.39	$0.14	($2.20)