PostRock Energy (PSTR) 10-K 28 Mar 14 2013 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, 2013	Mar. 03, 2014	Jun. 28, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'PSTR	'	'
Entity Registrant Name	'PostRock Energy Corp	'	'
Entity Central Index Key	'0001473061	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Common Stock, Shares Outstanding	'	31,437,312	'
Entity Public Float	'	'	$21.10
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Well-known Seasoned Issuer	'No	'	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and equivalents	$37	$525
Restricted cash	'	1,500
Accounts receivable-trade, net	7,722	7,207
Other receivables	194	180
Inventory	886	990
Other	820	2,100
Derivative financial instruments	54	1,771
Total	9,713	14,273
Oil and natural gas properties, full cost method of accounting, net	141,911	107,531
Other property and equipment, net	14,180	14,244
Equity investment	14,588	7,820
Derivative financial instruments	652	615
Other, net	2,038	2,180
Total assets	183,082	146,663
Current liabilities	'	'
Accounts payable	7,406	9,373
Revenue payable	4,397	4,447
Accrued expenses and other	4,055	4,928
Derivative financial instruments	1,937	4,449
Total	17,795	23,197
Derivative financial instruments	1,796	2,638
Long-term debt	92,000	57,500
Asset retirement obligations	13,099	10,868
Other	75	316
Total liabilities	189,288	94,519
Commitments and contingencies	'	'
Stockholders' equity	'	'
Common stock, $0.01 par value; 100,000,000 authorized shares; issued—21,309,159 and 29,915,951; outstanding—21,309,159 and 29,556,263, respectively	299	213
Additional paid-in capital	397,170	396,732
Treasury stock, at cost	-512	'
Accumulated deficit	-426,992	-417,956
Total stockholders’ deficit	-30,034	-21,008
Total liabilities and stockholders’ deficit	183,082	146,663
Series A Preferred Stock [Member]	'	'
Current liabilities	'	'
Mandatorily redeemable preferred stock—6,000 shares at December 31, 2013	64,523	'
Series A Cumulative Redeemable Preferred Stock, $0.01 par value; 7,250 and 1,250 shares issued and outstanding, respectively	23,828	73,152
Series B Preferred Stock [Member]	'	'
Stockholders' equity	'	'
Preferred stock, $0.01 par value; 5,000,000 authorized shares; 265,095 and 113,521 shares of Series B Voting Preferred Stock issued and outstanding, respectively	$1	$3

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	29,915,951	21,309,159
Common stock, shares outstanding	29,556,263	21,309,159
Series A Preferred Stock [Member]	'	'
Mandatorily redeemable preferred stock, shares	6,000	'
Cumulative redeemable preferred stock, par value	$0.01	$0.01
Cumulative redeemable preferred stock, shares issued	1,250	7,250
Cumulative redeemable preferred stock, shares outstanding	1,250	7,250
Preferred stock, shares outstanding	7,250	7,250
Series B Preferred Stock [Member]	'	'
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	113,521	265,095
Preferred stock, shares outstanding	113,251	265,095

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues	'		'		'
Natural gas sales	$51,489,000		$43,911,000		$72,812,000
Crude oil sales	18,200,000		8,640,000		7,075,000
Gathering	2,611,000		2,444,000		5,239,000
Total	72,300,000		54,995,000		85,126,000
Costs and expenses	'		'		'
Production expense	40,085,000		42,213,000		47,136,000
General and administrative	15,990,000		14,810,000		16,005,000
Litigation reserve	0		0		11,592,000
Depreciation, depletion and amortization	27,369,000		27,669,000		24,088,000
Impairment of oil and gas properties	0		5,919,000		0
(Gain) loss on disposal of assets	-194,000		295,000		-10,557,000
Acquisition cost	348,000		'		'
Total	83,598,000		90,906,000		88,264,000
Operating loss	-11,298,000		-35,911,000		-3,138,000
Other income (expense)	'		'		'
Realized gains (losses) from derivative financial instruments	-2,271,000	[1]	73,162,000	[1]	33,692,000	[1]
Unrealized gains (losses) from derivative financial instruments	1,672,000		-66,708,000		1,737,000
Gain (loss) from equity investment	6,768,000		-5,174,000		-4,607,000
Gain on forgiveness of debt	'		255,000		1,647,000
Other income	12,000		111,000		207,000
Interest expense	-3,740,000		-10,454,000		-10,154,000
Interest income	1,000		2,000		3,000
Total	2,442,000		-8,806,000		22,525,000
Income (loss) from continuing operations	-8,856,000		-44,717,000		19,387,000
Income taxes	180,000		0		0
Income (loss) from discontinued operations	-9,036,000		-44,717,000		19,387,000
Loss from discontinued operations	'		-2,855,000		643,000
Net income (loss)	-9,036,000		-47,572,000		20,030,000
Preferred stock dividends	-11,047,000		-9,083,000		-7,779,000
Accretion of redeemable preferred stock	-3,283,000		-2,238,000		-1,580,000
Net income (loss) available to common stockholders	($23,366,000)		($58,893,000)		$10,671,000
Net income (loss) per share common share	'		'		'
Basic income (loss) per share—continuing operations	($0.93)		($4.12)		$1.14
Basic income (loss) per share—discontinued operations	'		($0.21)		$0.07
Basic income (loss) per share	($0.93)		($4.33)		$1.21
Diluted income (loss) per share—continuing operations	($0.93)		($4.12)		$0.67
Diluted income (loss) per share—discontinued operations	'		($0.21)		$0.04
Diluted income (loss) per share	($0.93)		($4.33)		$0.71
Weighted average common shares outstanding	'		'		'
Basic	25,068,574	[2]	13,595,843	[2]	8,785,551	[2]
Diluted	25,068,574		13,595,843		15,049,720
[1]	2012 includes $30.2 million received from exiting above market natural gas swap contracts originally scheduled for delivery in 2013.
[2]	Includes vested common shares in the Company’s deferred compensation plan and vested deferred restricted stock units, both of which will deliver shares to participants at a later date. Although shares have not been delivered on these awards, all conditions for issuance and delivery have been met. Pursuant to FASB ASC 260-10-45-13, such shares are to be included in the denominator in calculating basic earnings per share.

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities	'	'	'
Net income (loss)	($9,036)	($47,572)	$20,030
Adjustments to reconcile net income (loss) to net cash flows from operating activities	'	'	'
Depreciation, depletion and amortization	27,369	30,206	27,662
Impairment of oil and gas properties	0	5,919	0
Share-based and other compensation	4,268	2,224	1,258
Amortization of deferred loan costs	461	2,820	1,709
Change in fair value of derivative financial instruments	-1,672	67,186	-1,737
Litigation reserve	'	'	6,042
Loss (gain) on disposal of assets	-194	5,735	-10,560
Gain on forgiveness of debt	'	-255	-1,647
Loss (gain) from equity investment	-6,768	5,174	4,607
Other non-cash changes to items affecting net loss	497	409	618
Changes in operating assets and liabilities	'	'	'
Accounts receivable	-529	1,519	2,696
Other current assets	578	5,020	-1,281
Other assets	16	33	-649
Accounts payable	-3,094	2,453	-2,521
Accrued expenses	-512	-11,701	-3,502
Other	-141	-51	-17
Net cash flows from operating activities	11,243	69,119	42,708
Cash flows from investing activities	'	'	'
Restricted cash	1,500	-1,500	28
Proceeds from sale of equity securities	'	'	1,634
Equity investment	'	'	-12,883
Expenditures for equipment, development, leasehold and pipeline	-52,283	-16,759	-29,338
Proceeds from sale of discontinued pipeline	'	53,397	'
Proceeds from sale of assets	1,111	496	12,723
Net cash flows from (used in) investing activities	-49,672	35,634	-27,836
Cash flows from financing activities	'	'	'
Proceeds from debt	98,500	57,500	3,000
Repayments of debt	-64,000	-193,000	-18,319
Proceeds from stock option exercise	'	'	66
Debt and equity financing costs	-635	-2,301	'
Proceeds from issuance of common stock	4,076	20,724	'
Proceeds from issuance of preferred stock and warrants	'	12,500	'
Net cash flows from (used in) financing activities	37,941	-104,577	-15,253
Net increase (decrease) in cash and cash equivalents	-488	176	-381
Cash and equivalents beginning of period	525	349	730
Cash and equivalents end of period	$37	$525	$349

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Deficit (USD $)	Preferred Stock [Member]	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Deficit [Member]	Series B Preferred Stock [Member]	Total
In Thousands, except Share data	Series B Preferred Stock [Member]
Beginning balance at Dec. 31, 2010	'	$2	$82	$377,538	'	($390,414)	'	($12,792)
Beginning balance, common shares at Dec. 31, 2010	'	'	8,238,982	'	'	'	'	'
Beginning balance, preferred shares at Dec. 31, 2010	'	195,842	'	'	'	'	'	'
Stock-based compensation	'	'	1	1,252	'	'	'	1,253
Stock-based compensation, shares	'	'	75,169	'	'	'	'	'
Restricted stock grants, net of forfeitures and cancellations	'	'	5	'	'	'	'	5
Restricted stock grants, net of forfeitures and cancellations, shares	'	'	460,000	'	'	'	'	'
Issuance of stock	'	'	11	4,833	'	'	'	4,844
Issuance of stock, shares	19,820	'	1,141,186	'	'	'	'	'
Issuance of warrants	'	'	'	3,763	'	'	'	3,763
Stock option exercises	'	'	'	66	'	'	'	66
Stock option exercises, shares	'	'	20,000	'	'	'	'	'
Preferred stock dividends	'	'	'	-7,779	'	'	'	-7,779
Preferred stock accretion	'	'	'	-1,580	'	'	'	-1,580
Net income (loss)	'	'	'	'	'	20,030	'	20,030
Ending balance at Dec. 31, 2011	'	2	99	378,093	'	-370,384	'	7,810
Ending balance, common shares at Dec. 31, 2011	'	'	9,935,337	'	'	'	'	'
Ending balance, preferred shares at Dec. 31, 2011	'	215,662	'	'	'	'	'	'
Stock-based compensation	'	'	'	2,213	'	'	'	2,213
Restricted stock grants, net of forfeitures and cancellations	'	'	11	'	'	'	'	11
Restricted stock grants, net of forfeitures and cancellations, shares	'	'	1,085,104	'	'	'	'	'
Issuance of stock	1	'	103	20,342	'	'	1	20,445
Issuance of stock, shares	49,433	'	10,280,718	'	'	'	'	'
Issuance of warrants	'	'	'	7,405	'	'	'	7,405
Preferred stock dividends	'	'	'	-9,083	'	'	'	-9,083
Preferred stock accretion	'	'	'	-2,238	'	'	'	-2,238
Net income (loss)	'	'	'	'	'	-47,572	'	-47,572
Ending balance at Dec. 31, 2012	'	3	213	396,732	'	-417,956	'	-21,008
Ending balance, common shares at Dec. 31, 2012	'	'	21,301,159	'	'	'	'	21,309,159
Ending balance, preferred shares at Dec. 31, 2012	'	265,095	'	'	'	'	265,095	'
Stock-based compensation	'	'	'	3,213	'	'	'	3,213
Restricted stock grants, net of forfeitures and cancellations	'	'	-4	'	-39	'	'	-43
Restricted stock grants, net of forfeitures and cancellations, shares	'	'	-393,760	'	35,166	'	'	'
Funding of 401K and deferred compensation plans	'	'	7	1,397	-473	'	'	931
Funding of 401K and deferred compensation plans, shares	'	'	649,527	'	324,522	'	'	325,005
Warrant exchange (see Note 12)	'	-3	11	-4,366	'	'	'	-4,358
Warrant exchange (see Note 12), shares	'	-222,413	1,123,981	'	'	'	'	'
Issuance of stock	1	'	72	10,540	'	'	1	10,612
Issuance of stock, shares	70,839	'	7,235,044	'	'	'	'	'
Issuance of warrants	'	'	'	3,984	'	'	'	3,984
Preferred stock dividends	'	'	'	-11,047	'	'	'	-11,047
Preferred stock accretion	'	'	'	-3,283	'	'	'	-3,283
Net income (loss)	'	'	'	'	'	-9,036	'	-9,036
Ending balance at Dec. 31, 2013	'	$1	$299	$397,170	($512)	($426,992)	'	($30,034)
Ending balance, common shares at Dec. 31, 2013	'	'	29,915,951	'	359,688	'	'	29,556,263
Ending balance, preferred shares at Dec. 31, 2013	'	113,521	'	'	'	'	113,251	'

Business_Organization

Business Organization	12 Months Ended
	Dec. 31, 2013
Business Organization [Abstract]	'
Business Organization	'
	Note 1—Business Organization
	PostRock Energy Corporation (“PostRock”) is an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. It manages its business in one segment, oil and gas and production. Its primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma, and Central Oklahoma. It also has minor oil and gas producing properties in the Appalachian Basin. Unless the context requires otherwise, any reference to “the Company”, “we”, “us”, and “our” is to PostRock and subsidiaries.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Note 2—Summary of Significant Accounting Policies
	Principles of Consolidation—These consolidated financial statements include PostRock’s and its subsidiaries’ accounts. Subsidiaries in which PostRock directly or indirectly owns more than 50% of the outstanding voting securities or those in which PostRock has effective control over are generally accounted for under the consolidation method of accounting. Under this method, a subsidiaries’ balance sheet and results of operations are reflected within the Company’s consolidated financial statements. All significant intercompany accounts and transactions have been eliminated.
	Use of Estimates in the Preparation of Financial Statements—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s most significant recurring estimates are based on remaining proved oil and gas reserves. Estimates of proved reserves are key components of the Company’s depletion rate for oil and gas properties and its full cost ceiling test limitation. In addition, estimates are used in computing fair value of impaired assets, taxes, asset retirement obligations, fair value of derivative contracts and other items. Actual results could differ from these estimates.
	Cash and Cash Equivalents—The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Cash balances are maintained at a few financial institutions that are insured by the Federal Deposit Insurance Corporation although such balances at times are in excess of the insured amount; however, no losses have been recognized as a result of this circumstance. During 2011, the Company began utilizing a controlled disbursement cash account which is funded when outstanding checks and electronic payments are presented for payment and an overdraft is the normal book balance. The Company’s policy has been to fund these outstanding checks and electronic payments as they clear through the banking system with customer receipts and borrowings under its Borrowing Base Credit Facility (as defined below). The Company accounts for such book overdrafts by reporting them in accounts and revenue payable in its consolidated balance sheets and including the change in such amounts in cash flows from operating activities in its consolidated statements of cash flows. Outstanding checks and electronic payments included in accounts and revenue payable at December 31, 2012 and 2013, amounted to $6.6 million and $4.5 million, respectively.
	Accounts Receivable—The Company conducts the majority of its operations in Kansas and Oklahoma and operates exclusively in the oil and gas industry. Receivables are generally unsecured; however, the Company has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements. Management periodically assesses the accounts receivable and establishes an allowance for estimated uncollectible amounts. Accounts estimated to be uncollectible are charged to operations in the period the reserve is established. The allowance for doubtful accounts was approximately $193,000 and $194,000 at December 31, 2012 and 2013, respectively.
	Inventory—Inventory includes tubular goods and other lease and well equipment which the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method.
	Oil and Natural Gas Properties—The Company uses the full cost method of accounting for oil and gas properties. Under the full cost method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of its oil and gas properties are capitalized.
	Oil and gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved oil and gas reserves. Estimation of proved oil and gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates that are materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of oil and gas properties such will result in an amortization rate materially different from the amortization rate calculated upon recognition of gains or losses.
	Under the full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum less income tax effects (the “ceiling limitation”). The Company performs a quarterly ceiling test to evaluate whether the net book value of its full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion, and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ (deficit) equity in the period of occurrence and typically results in lower depreciation, depletion, and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The risk that the Company will be required to write down the carrying value of its oil and gas properties increases when oil and gas prices are depressed, even if low prices are temporary. This is partially mitigated by the use of an unweighted arithmetic first day of the month price for trailing average twelve-month market prices to determine the ceiling. In addition, a write-down may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly.
	Unevaluated Properties—The costs directly associated with unevaluated oil and gas properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs and cumulative drilling costs to date associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in the Company’s unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of numerous factors, including intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, assignment of proved reserves and economic viability of development if proved reserves are assigned. Any impairments of unevaluated properties are transferred to the amortization base.
	Capitalized General and Administrative Expenses—Under the full cost method of accounting, a portion of general and administrative expenses that are directly attributable to acquisition, exploration, and development activities are capitalized to the full cost pool. The capitalized costs include salaries, related fringe benefits, cost of consulting services and other costs directly associated with those activities. In addition to costs related to acquisition, exploration, and development activities, the Company has also capitalized certain software costs. The Company’s capitalized general and administrative costs including software costs were $1.1 million, $904,000 and $1.3 million for the years ended December 31, 2011, 2012 and 2013, respectively.
	Capitalized Interest Costs—The Company capitalizes interest based on the cost of major development projects. Capitalized interest was $51,000,  $11,000 and nil for the years ended December 31, 2011, 2012 and 2013, respectively.
	Other Property and Equipment—The cost of other property and equipment is depreciated over the estimated useful lives of the related assets. The cost of leasehold improvements is depreciated over the lesser of the length of the related leases or the estimated useful lives of the assets.
	Upon disposition or retirement of property and equipment, other than oil and gas properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is recognized in the statement of operations in the period of sale or disposition. Maintenance and repair costs are charged to operating expense as incurred.
	Impairment—Long-lived assets such as property and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. If the carrying amount of such assets exceeds their undiscounted estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets.
	Equity Investment—The Company elected to measure its investment in Constellation Energy Partners LLC (“CEP”) at fair value with changes in fair value included in the consolidated statements of operations. If the Company had not elected the fair value method, the investment would have previously qualified for the equity method of accounting, under which the Company’s proportionate share of the investee’s income would have been reported in the consolidated statements of operations.
	Asset Retirement Obligations—Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost and the corresponding liability should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its natural gas and oil wells. Asset retirement obligations associated with the retirement of a tangible long-lived asset are recognized as a liability in the period incurred or when it becomes determinable that there is a legal or contractual obligation to dismantle or dispose of the asset and reclaim or remediate any related property at the end of its useful life, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. The Company has not recorded an asset retirement obligation relating to its gathering system because it does not have any legal or constructive obligations relative to asset retirements of the gathering system.
	Derivative Instruments—The Company utilizes derivative instruments in conjunction with marketing and trading activities to manage price risk attributable to its forecasted sales of oil and gas production.
	The Company does not designate its oil and natural gas derivative contracts as hedges under ASC 815 Derivatives and Hedging  although it believes that such contracts are effective hedges of its commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on the Company’s consolidated balance sheets under the caption “Derivative financial instruments.” Changes in the fair value of these derivative financial instruments are recorded in earnings.  The Company recognizes all unrealized and realized gains and losses related to these contracts on its consolidated statements of operations under the captions “Realized gain (loss) from derivative financial instruments” and “Unrealized gain (loss) from derivative financial instruments” both which are components of “Other income (expense)”.
	The Company has exposure to credit risk to the extent a counterparty to a derivative instrument is unable to meet its settlement commitment. It actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.
	Legal—The Company is subject to certain legal proceedings, claims and liabilities which arise in the ordinary course of its business. It accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These estimates are adjusted as additional information becomes available or circumstances change.
	Revenue Recognition—Revenue from the Company’s oil and gas operations is derived from the sale of produced oil and natural gas. The Company uses the sales method of accounting for the recognition of oil and gas revenue. Because there is a ready market for oil and gas, the Company sells its oil and gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title and risk of loss is transferred based on the Company’s net revenue interests. Gathering revenue is recognized at the time the gas is gathered or transported through the system and delivered to a third party as evidenced by a contract.
	Environmental Costs—Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. The Company has no environmental costs accrued for the periods presented.
	Stock-Based Compensation—The Company grants various types of stock-based awards including stock options, restricted stock and restricted stock units to its employees and non-employee directors. The Company accounts for stock-based compensation in accordance with FASB ASC 718 Compensation – Stock Compensation where the awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the consolidated statement of operations over the applicable requisite service periods. The fair value of stock option awards is determined using a Black-Scholes pricing model where volatility is derived from a peer group of companies.
	Deferred compensation plan—The Company’s deferred compensation plan permits selected employees and members of its board of directors to defer part or all of their eligible compensation. The Company accounts for this deferred compensation in accordance with FASB ASC 710 Compensation – General. The Company issues common stock into a rabbi trust created to hold the assets associated with the plan. A participant’s deferred compensation is credited with earnings, gains and losses based on the Company’s common stock, the only investment option currently available under the plan. The Company may also make discretionary employer credits in an amount it determines each plan year. Distributions to participants will be made in shares of the Company’s common stock. Company shares held in the rabbi trust are recorded as treasury stock in the consolidated balance sheets. Since the deferred compensation arrangement currently does not permit diversification and only allows for settlement by delivery of Company common stock, the obligation is recorded as a component of paid-in-capital and changes in the fair value of the obligation are not recognized.
	Income Taxes—The Company records its income taxes using an asset and liability approach in accordance with the provisions of the FASB ASC 740 Income Taxes. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences (primarily property and equipment and the net operating loss carry forward) between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under FASB ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2012 and 2013,  a full valuation allowance was recorded against the Company’s net deferred tax assets.
	The Company regularly analyzes tax positions taken or expected to be taken in a tax return based on the threshold condition prescribed under FASB ASC 740. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. The Company accrues interest and penalties related to uncertain tax positions as income tax expense.
	Net Income (Loss) per Common Share—Basic earnings (loss) per share is calculated by dividing net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the period. The Company also includes contingently issuable shares in basic earnings (loss) per share when there is no circumstance under which those shares would not be issued. These include vested shares under the Company’s deferred compensation plan and vested deferred restricted stock units as all necessary conditions have been satisfied for the issuance of those shares other than the passage of time. Diluted earnings (loss) per share assumes the conversion of all potentially dilutive securities (warrants, stock options and restricted stock awards) and is calculated by dividing net income (loss) by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities under the treasury stock method.
	Concentrations of Market Risk—The Company’s future results will be affected by the market price of oil and gas. The availability of a ready market for oil and gas will depend on numerous factors beyond the Company’s control, including weather, production of oil and gas, imports, marketing, competitive fuels, proximity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil and gas, the regulatory environment, and other regional and political events, none of which can be predicted with certainty.
	Concentrations of Credit Risk—Financial instruments, which subject the Company to concentrations of credit risk, consist primarily of cash and accounts receivable. Risk with respect to receivables at December 31, 2012 and 2013, arise substantially from the sales of oil and gas. The following table discloses the percentage of consolidated revenues from our major customers:
		Year Ended December 31,
		2012		2013
	British Petroleum Energy Company	22	%	56	%
	ONEOK Energy and Marketing and Trading Company	34	%	11	%
	Sunoco	9	%	11	%
	Fair Value—The Company applies the provisions of FASB ASC 820 Fair Value Measurements and Disclosures. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.
	FASB ASC 820 also establishes a hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:
	•Level 1—Quoted prices available in active markets for identical assets or liabilities at the reporting date.
	•Level 2—Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable at the reporting date. Level 2 consists primarily of non-exchange traded commodity derivatives.
	•Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources.
	The Company classifies assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Transfers of assets and liabilities between Level 1 and Level 2 are recognized at the end of a reporting period. The Company prioritizes the use of the highest level inputs available in determining fair value.
	Recent Accounting Pronouncements
	In December 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities requiring entities to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on the financial position of an entity. The disclosure affects all entities with financial instruments and derivatives that are either offset on the balance sheet or subject to a master netting arrangement, irrespective of whether they are offset on the balance sheet. This information will enable users of an entity’s financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. The guidance is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods. Other than the additional disclosure requirements, which are presented in Note 6—Derivative Financial Instruments, the Company’s adoption of this guidance did not have an impact on its financial statements.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2013
Acquisitions and Divestitures [Abstract]	'
Acquisitions and Divestitures	'
	Note 3—Acquisitions and Divestitures
	Acquisitions
	During May 2013, we acquired leasehold interests in 4,300 acres located in Lincoln and Payne Counties in Oklahoma. The total purchase price of the acquired interests was $1.9 million which was paid in cash of $1.7 million and 126,602 shares of the Company’s common stock.
	During November 2013, we acquired a 50% working interest in 110 operated acres and three producing wells in Seminole County, Oklahoma, for $750,000 in cash.
	During November 2013, the Company closed on an acquisition of oil and natural gas assets located in Pottawatomie, Cleveland and McClain Counties in Central Oklahoma. The acquisition included approximately 22,000 net acres of leasehold mineral interests, including certain producing oil and gas properties and related wells.  The total purchase price of the acquired assets was approximately $10.0 million and was paid in cash and 4,516,129 shares of the Company’s common stock. The Company estimated the fair value of the assets and liabilities acquired as of the acquisition date. The following table discloses the fair value of consideration transferred to the sellers as wells as the purchase price allocation of the assets and liabilities assumed:
	Consideration given (in thousands)
	Cash	$	3,440
	Common stock		6,548
	Total consideration given	$	9,988
	Amounts recognized for fair value of assets acquired and liabilities assumed
	Proved oil and natural gas properties	$	7,081
	Unproved oil and natural gas properties		3,253
	Crude oil inventory		177
	Accounts receivable		167
	Asset retirement obligations		-538
	Accounts payable		-152
	Total fair value of oil and gas properties acquired	$	9,988
	To estimate the fair values of the properties as of the acquisition date, the Company utilized a discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows: (i) estimated ultimate recovery of crude oil and natural gas as prepared by a third party reservoir engineering consultant; (ii) estimated future commodity prices based on NYMEX crude oil and gas futures prices as of the acquisition date and adjusted for estimated location and quality differentials; (iii) estimated future production rates; and (iv) estimated timing and amounts of future operating and development costs. To estimate the fair value of proved properties, the Company discounted the future net cash flows using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. The valuation of the assets and liabilities received is a Level 3 valuation under the fair value hierarchy.  The Company has not presented pro forma information for the acquired businesses because the revenues and expenses from the acquired properties were not material to the results of operations of the Company.
	Subsequent Event
	During January 2014, the Company acquired additional well interests for the assets mentioned above in Pottawatomie, Cleveland, and McClain Counties in Central Oklahoma. The total purchase price of the acquired well interests was $1.8 million which was paid in cash of approximately $900,000 and 725,806 shares of the Company’s common stock.
	Divestitures
	KPC Sale—In September 2012, the Company sold KPC to MV Pipelines, LLC (“MV”) for $53.4 million in cash after a working capital adjustment. Details of the transaction are discussed further in Note 16 — Discontinued Operations.
	Appalachia Basin Sale—  On December 24, 2010, the Company entered into an agreement with Magnum Hunter Resources Corporation (“MHR”) to sell certain oil and gas properties and related assets in West Virginia. The sale closed in three phases for a total of $44.6 million. The first phase closed in December 2010 for $28 million while the following two phases closed in January and June 2011 for a combined $16.6 million. The amount received for the first and second phases was paid half in cash and half in MHR common stock, while the amount received for the third phase was paid entirely in cash.
	Gains of $13.7 million and $12.5 million, net of $728,000 and $2.6 million in selling costs and adjustments, were recorded in 2010 and 2011 related to the three phases of the sale. The corresponding reduction in the Company’s oil and gas full cost pool for the three phases of the sale was $13.6 million and $1.5 million in 2010 and 2011, respectively.
	Of the total proceeds received from all three phases of the sale, $6.4 million was set aside in escrow to cover potential claims for indemnity and title defects. During 2012, $5.7 million of escrowed funds relating to the first and second closing was released after net claims of $219,000 were paid. Of the $5.7 million released to the Company, $1.3 million was retained by the Company while $4.4 million was paid to Royal Bank of Canada (“RBC”) under the asset sale agreement discussed in Note 10. The $219,000 of net claims paid out of escrow effectively reduced the net proceeds received from the sale, and along with certain post-closing adjustments, resulted in a $266,000 reduction in the gain on sale recognized in 2012.
	At December 31, 2012, the remaining balance in escrow, which was related to the third closing, was $564,000. The escrow agreement expired by its terms on December 31, 2012, and the escrowed funds were released to MHR in January 2013.

Other_Balance_Sheet_Items

Other Balance Sheet Items	12 Months Ended
	Dec. 31, 2013
Other Balance Sheet Items [Abstract]	'
Other Balance Sheet Items	'
	Note 4—Other Balance Sheet Items
	The following describes the components of the following consolidated balance sheet items at December 31, 2012 and 2013:
		December 31,
		2012		2013
		(in thousands)
	Other current assets
	Prepaid fees and deposits	$	1,036	$	820
	Escrowed funds from Appalachian Basin sale (1)		564		—
	Escrowed funds from KPC sale (2)		500		—
	Total	$	2,100	$	820
	Other noncurrent assets, net
	Deferred financing costs	$	1,668	$	1,547
	Noncurrent deposits and other		512		491
	Total	$	2,180	$	2,038
	Accrued expenses and other
	Interest	$	56	$	39
	Employee-related costs and benefits		1,790		1,062
	Non-income related taxes		88		72
	Escrowed funds due to third parties (3)		400		—
	KPC site cleanup costs (4)		313		—
	Fees for services		1,327		1,127
	Asset retirement obligations		—		129
	Current income taxes		—		80
	Other		954		1,546
	Total	$	4,928	$	4,055
	Other noncurrent liabilities
	Lease termination costs	$	255	$	75
	Other		61		—
	Total	$	316	$	75
	____________
	(1)Escrowed funds relate to the proceeds from the Appalachian Basin sale. The escrowed funds are restricted to cover indemnities and title defects related to the sale. In 2012, $5.7 million in escrowed funds were released after $219,000 in net claims were paid. The remaining $564,000 was released to MHR in January 2013.
	(2)Escrowed funds relate to the proceeds from the KPC sale and were released to the Company in January 2013 upon acceptable cleanup of a site previously owned by KPC.
	(3)The balance at December 31, 2012, represented escrowed funds from the Appalachian Basin sale that were released to MHR in January 2013.
	(4)Represent accrued costs for cleanup of a site previously owned by KPC as discussed above.
	Deferred Financing Costs—The Company’s expense related to amortizing or writing off deferred financing costs was $1.7 million, $2.8 million and $461,000 for the years ended December 31, 2011, 2012 and 2013, respectively. These costs are included in interest expense. Included in the amounts above was a $1.2 million write-off of unamortized debt issuance costs for the year ended December 31, 2012, made in connection with the refinancing of the Company’s credit facility that year.

Property

Property	12 Months Ended
	Dec. 31, 2013
Property [Abstract]	'
Property	'
	Note 5—Property
	Oil and gas properties, and other property and equipment were comprised of the following at December 31, 2012 and 2013:
		December 31,
		2012		2013
		(in thousands)
	Oil and gas properties under the full cost method of accounting
	Properties being amortized	$	353,093	$	405,895
	Properties not being amortized		31		4,862
	Total oil and gas properties, at cost		353,124		410,757
	Less accumulated depletion, depreciation and amortization		-245,593		-268,846
	Oil and gas properties, net		107,531		141,911
	Other property and equipment at cost	$	30,247	$	30,019
	Less accumulated depreciation		-16,003		-15,839
	Other property and equipment, net	$	14,244	$	14,180
	Depreciation on other property and equipment is computed on the straight-line basis over the following estimated useful lives:
	Buildings	25 years
	Machinery and equipment	10 years
	Software and computer equipment	3 years
	Furniture and fixtures	10 years
	Vehicles	5 years
	For the years ended December 31, 2011, 2012 and 2013, depletion, depreciation and amortization expense on oil and gas properties amounted to $19.6 million, $23.3 million and $23.3 million, respectively. For the years ended December 31, 2011, 2012 and 2013, depreciation expense on other property and equipment amounted to $3.9 million, $3.6 million and $3.2 million, respectively. Depreciation and amortization expense on the Company’s interstate pipeline that was sold in September 2012 is disclosed in Note 16. During 2011, the Company elected to shorten the depreciable lives of selected vehicle and equipment property in its pipeline segment as well as technologically limited assets, including computer hardware and communication devices, in service throughout the Company. The overall impact of this change was to increase depletion, depreciation and amortization by $0.7 million in 2011 and align the remaining depreciable lives for these assets along the lines of the demonstrated useful lives of these assets.

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Financial Instruments [Abstract]	'
Derivative Financial Instruments	'
	Note 6—Derivative Financial Instruments
	The Company is exposed to commodity price risk and management believes it prudent to periodically reduce exposure to cash-flow variability resulting from this volatility. Accordingly, the Company enters into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in its oil and gas production. Derivative financial instruments are also used to manage commodity price risk inherent in customer pricing requirements and to fix margins on the future sale of oil and natural gas. Specifically, the Company may utilize futures, swaps and options.
	Derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are currently with two counterparties. The Company generally executes commodity derivative instruments under master agreements which allow it, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.
	The Company monitors the creditworthiness of its counterparties; however, it is not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, it may be limited in its ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer its position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices as well as incur a loss. The Company includes a measure of counterparty credit risk in its estimates of the fair values of derivative instruments in an asset position. At December 31, 2013, the Company was a net obligor with respect to outstanding derivative contracts with both of its counterparties and therefore utilized its own credit risk in estimating the fair value of those derivatives.
	The Company entered into an International Swap Dealers Association Master Agreement (“ISDA”) with each of its two counterparties for which it holds derivative contracts. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The Company has multiple oil swap contracts that could be offset under these provisions but has elected not to offset the fair values of its derivative assets against the fair value of its derivative liabilities on its consolidated balance sheets. The ISDA also includes a master netting arrangement in the event of early termination or default.
	The Company does not designate its derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, it recognizes the change in the respective instruments’ fair value currently in earnings. The tables below outline the classification of derivative financial instruments on the consolidated balance sheet:
				December 31,
				2012			2013
	Derivative Financial Instruments		Balance Sheet Location	(in thousands)
	Commodity contracts		Current derivative financial instrument asset	$	1,771		$	54
	Commodity contracts		Long-term derivative financial instrument asset		615			652
	Commodity contracts		Current derivative financial instrument liability		-4,449			-1,937
	Commodity contracts		Long-term derivative financial instrument liability		-2,638			-1,796
				$	-4,701		$	-3,027
	Gains and losses associated with derivative financial instruments related to oil and gas production were as follows for the periods indicated:
		Year Ended December 31,
		2011			2012			2013
		(in thousands)
	Realized gains (losses)(1)	$	33,692		$	73,162		$	-2,271
	Unrealized gains (losses)		1,737			-66,708			1,672
	Total gain (loss) from derivative financial instruments	$	35,429		$	6,454		$	-599
	___________
	(1)2012 includes $30.2 million received from exiting above market natural gas swap contracts originally scheduled for delivery in 2013.
	The following table summarizes the estimated volumes, fixed prices and fair values attributable to all of the Company’s oil and gas derivative contracts at December 31, 2013.
			Year Ending December 31,
			2014			2015			2016			Total
			($ in thousands, except per unit data)
	Natural Gas Swaps
	Contract volumes (MMBtu)			10,327,572			8,983,560			7,814,028			27,125,160
	Weighted-average fixed price per MMBtu		$	4.01		$	4.01		$	4.01		$	4.01
	Fair value, net		$	-1,800		$	-1,076		$	-719		$	-3,595
	Crude Oil Swaps
	Contract volumes (Bbl)			116,076			71,568			65,568			253,212
	Weighted-average fixed price per Bbl		$	95.19		$	92.73		$	90.33		$	93.23
	Fair value, net		$	-53		$	281		$	340		$	568
	Total fair value, net		$	-1,853		$	-795		$	-379		$	-3,027
	The following table summarizes the estimated volumes, fixed prices and fair values attributable to all of the Company’s oil and gas derivative contracts at December 31, 2012:
		Year Ending December 31,
		2013			2014			2015			2016			Total
		($ in thousands, except per unit data)
	Natural Gas Swaps
	Contract volumes (MMBtu)		3,747,285			4,324,032			3,755,184			3,765,840			15,592,341
	Weighted-average fixed price per MMBtu	$	3.95		$	3.95		$	3.95		$	3.96		$	3.95
	Fair value, net	$	1,270		$	-320		$	-908		$	-1,410		$	-1,368
	Natural Gas Basis Swaps
	Contract volumes (MMBtu)		9,000,003			—			—			—			9,000,003
	Weighted-average fixed price per MMBtu	$	-0.71		$	—		$	—		$	—		$	-0.71
	Fair value, net	$	-4,448		$	—		$	—		$	—		$	-4,448
	Crude Oil Swaps
	Contract volumes (Bbl)		65,892			61,680			58,164			53,892			239,628
	Weighted-average fixed price per Bbl	$	101.70		$	97.00		$	93.40		$	91.10		$	96.09
	Fair value, net	$	546		$	276		$	168		$	125		$	1,115
	Total fair value, net	$	-2,632		$	-44		$	-740		$	-1,285		$	-4,701
	The following table discloses and reconciles the gross amounts as presented in the consolidated balance sheets to the net amounts allowed under a master netting arrangement. Amounts not offset on the condensed consolidated balance sheets represent positions that do not meet all the conditions for "a right of offset" or positions for which the Company has elected not to offset.
		December 31,
		2012			2013
		(in thousands)
	Derivative Assets
	Gross amounts of recognized assets	$	2,386		$	706
	Gross amounts offset in the balance sheet		—			—
	Net amounts of assets presented in the balance sheet		2,386			706
	Gross amounts not offset in the balance sheet		-2,386			-706
	Net amount	$	—		$	—
Derivative Liabilities
Gross amounts of recognized liabilities	$	7,087		$	3,733
Gross amounts offset in the balance sheet		—			—
Net amounts of liabilities presented in the balance sheet		7,087			3,733
Gross amounts not offset in the balance sheet		-2,386			-706
Net amount	$	4,701		$	3,027

Financial_Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2013
Financial Instruments [Abstract]	'
Financial Instruments	'
	Note 7—Financial Instruments
	The Company’s financial instruments include commodity derivatives, debt, cash, receivables, payables, redeemable preferred stock and equity securities. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of those instruments.
	The Company classifies assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The Company did not own any Level 3 assets or liabilities during 2012 and 2013 and there were no movements between Levels 1 and 2 for the respective time period.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis—The following table sets forth, by level within the fair value hierarchy, our assets and liabilities that were measured at fair value on a recurring basis at December 31, 2012 and 2013:
								Total Net Fair
		Level 1		Level 2		Level 3		Value
		(in thousands)
	At December 31, 2012
	Equity investment	$	6,984	$	836	$	—	$	7,820
	Derivative financial instruments—assets		—		2,386		—		2,386
	Derivative financial instruments—liabilities		—		-7,087		—		-7,087
	Total	$	6,984	$	-3,865	$	—	$	3,119
	At December 31, 2013
	Equity investment	$	14,205	$	383	$	—	$	14,588
	Derivative financial instruments—assets		—		706		—		706
	Derivative financial instruments—liabilities		—		-3,733		—		-3,733
	Total	$	14,205	$	-2,644	$	—	$	11,561
	Commodity Derivative Instruments—The Company’s oil and gas derivative instruments may consist of variable to fixed price swaps, collars and basis swaps. When possible, the Company estimates the fair values of these instruments based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates adjusted for counterparty credit risk. Counterparty credit risk is incorporated into derivative assets while the Company’s own credit risk is incorporated into derivative liabilities. Both are based on the current published credit default swap rates.
	Equity Investment—The Company owns an equity investment in CEP that was purchased in 2011. At December 31, 2013, the investment included 484,505 Class A Member Interests and 5,918,894 Class B Member Interests. Fair value for the Class B Member Interests, which are publicly traded, is based on market price and classified as a Level 1 measurement under the fair value hierarchy. Fair value for the Class A Member Interests, classified as a Level 2 measurement, is based on the market price of the publicly traded interests and a liquidity discount as the units are not publicly traded. At December 31, 2013, the fair values used for the Class A units and the Class B units were $0.79 and $2.40 per unit, respectively.
	Additional Fair Value Disclosures—The Company has 7,250 outstanding shares of Series A Cumulative Redeemable Preferred Stock (see Note 12—Redeemable Preferred Stock). At December 31, 2013, the obligation to redeem the preferred shares is reflected as debt (“Mandatorily redeemable preferred stock”) and temporary equity (“Series A Cumulative Redeemable Preferred Stock”) in the condensed balance sheet (see Note 12—Redeemable Preferred Stock).  At December 31, 2012, the entire obligation was reflected in temporary equity in the balance sheet. The fair value and the carrying value of these securities at December 31, 2012, were $91.3 million and $73.2 million, respectively. The fair value and the carrying value of these securities at December 31, 2013, were $30.9 million and $23.8 million, respectively for the portion reflected as temporary equity and $71.9 million and $64.5 million, respectively, for the portion reflected in debt. The fair value was determined by discounting the cash flows over the remaining life of the securities utilizing a LIBOR interest rate and a risk premium of approximately 7.1% and 12.9% at December 31, 2012 and 2013, respectively, which was based on companies with similar leverage ratios to PostRock. The Company has classified the valuation of these securities under Level 2 of the fair value hierarchy.
	The Company’s long term debt consists entirely of floating-rate facilities. The carrying amount of floating-rate debt approximates fair value because the interest rates paid on such debt are generally set for periods of six months or shorter.

Equity_Investment

Equity Investment	12 Months Ended
	Dec. 31, 2013
Equity Investment [Abstract]	'
Equity Investment	'
	Note 8—Equity Investment
	The Company elected the fair value option to account for its interest in CEP. The fair value option was chosen as the Company determined that the market price of CEP’s publicly traded interests provided a more accurate fair value measure of the Company’s investment in CEP. The Company has not elected the fair value option for any of its other assets and liabilities.
	The following table presents the mark-to-market gains (losses) on our equity investment, which are recorded as a component of other income (expense) in the consolidated statement of operations:
		Year ended December 31,
		2011			2012		2013
		(in thousands)
	Mark to market gains (losses) on equity investment	$	-4,607		$	-5,174	$	6,768
	The following table presents summarized condensed financial information of CEP.
		Year ended December 31,
		2011			2012		2013
		(in thousands)
	Gross revenues	$	105,217		$	59,335	$	46,381
	Gross profit (loss)(1)		29,453			-80,964		-25,589
	Net income (loss) from continuing operations (2)		—			-9,462		-25,857
	Net income (loss)		19,586			-86,543		-28,543
	____________
		-1		Equals revenues less operating expenses
		-2		Net income from continuing operations is not available for 2011
	On August 9, 2013, CEP announced that it had closed the transactions contemplated by a Contribution Agreement (the “Contribution Agreement”) with Sanchez Energy Partners I, LP (“Sanchez”)  pursuant to which Sanchez agreed to sell to CEP all of the equity of an entity that owns oil and natural gas properties located in Texas and Louisiana in exchange for consideration consisting of 4,724,407 CEP Class B units, 1,130,512 CEP Class A Units, one CEP Class Z Unit and $20,090,876 in cash, for an aggregate purchase price of approximately $30.4 million. CEP also announced that Sanchez, as the holder of a majority of the Company’s Class A Units, removed John R. Collins and Gary M. Pittman as the Company’s Class A managers and elected Antonio R. Sanchez, III and Gary Willinger to the CEP’s Board of Managers to serve as the Class A managers.
	On August 30, 2013, CEPM, a wholly owned subsidiary of the Company, together with Gary M. Pittman and John R. Collins, as Plaintiffs, filed suit in the Delaware Court of Chancery against CEP, CEP’s Chief Executive Officer, Stephen R. Brunner, Richard S. Langdon, Richard H. Bachmann and John N. Seitz, each a member of the five-person CEP Board of Managers, Sanchez Oil & Gas Corporation and Sanchez Energy Partners I, LP (collectively, the “Sanchez Defendants”), Antonio R. Sanchez, III and Gerald F. Willinger, as Defendants (Case No. 8856-VCL).
	The lawsuit arises from actions taken by the Defendants prior to and during the August 9, 2013, meeting of the CEP Board of Managers.  Specifically, the lawsuit alleges that the Defendants conspired to dilute CEPM’s ownership interest in CEP and thereby remove CEPM’s right, as the sole owner of Class A units, to select two Managers to the CEP Board of Managers. At the time of the August 9th meeting, Pittman and Collins were serving as CEPM’s duly selected members on the CEP Board of Managers.
	The suit asserts that by purporting to issue to the Sanchez Defendants 4,724,407 Class B units and 1,130,512 Class A units in connection with CEP’s purchase of the oil and gas properties, the Defendants acted in bad faith, violated CEP’s Operating Agreement, wrongfully interfered with CEPM’s contractual relations, and breached contractual and fiduciary obligations owed to CEPM. As such, the complaint further alleges that the Sanchez Defendants were without authority to remove Pittman and Collins as the Class A unit representatives on the Board of Managers and purportedly replace them with Defendants Sanchez and Willinger. Among other relief, Plaintiffs seek a declaration that the purported issuance of units to the Sanchez Defendants violates the CEP operating agreement and is therefore invalid and void.  Plaintiffs also seek to have Pittman and Collins reinstated to the CEP Board of Managers. Trial was initially scheduled for mid-December 2013,  but has been postponed indefinitely based on anticipated settlement in early 2014.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations [Abstract]	'
Asset Retirement Obligations	'
	Note 9—Asset Retirement Obligations
	The following table reflects the changes to asset retirement obligations for the periods indicated:
		Year Ended December 31,
		2012		2013
		(in thousands)
	Asset retirement obligations at beginning of period (1)	$	10,087	$	10,868
	Liabilities incurred		160		533
	Liabilities settled		-111		-88
	Acquisitions		—		538
	Accretion		743		811
	Revision of estimates		-11		566
	Asset retirement obligations at end of period	$	10,868	$	13,228
	Current portion of asset retirement obligations	$	—	$	129
	Noncurrent portion of asset retirement obligations at end of period	$	10,868	$	13,099
	____________
	(1)Amounts in the table do not include the asset retirement obligations of KPC which was divested by the Company during 2012.
	During 2013, revisions to the Company's asset retirement obligations totaled $566,000. The increase is due to higher estimated cost to plug an oil/gas well, salt water disposal (SWD) well, as well as a tank battery remediation costs.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-Term Debt [Abstract]	'
Long-Term Debt	'
	Note 10—Long-Term Debt
	The following is a summary of long-term debt at the dates indicated:
		December 31,
		2012		2013
		(in thousands)
	Borrowing Base Facility	$	57,500	$	92,000
	Less current maturities		—		—
	Total long-term debt	$	57,500	$	92,000
	Borrowing Base Facility
	The Company’s sole credit facility is the Third Amended and Restated Credit Agreement, dated as of December 20, 2012 (the “Borrowing Base Facility”), among PostRock Energy Services Corporation (“PESC”) and PostRock MidContinent Production, LLC (“MidContinent”), as borrowers, Citibank, N.A., as successor administrative and collateral agent, Royal Bank of Canada, as resigning administrative and collateral agent, and the lenders and other loan parties party thereto. The Borrowing Base Facility is a $200 million senior secured revolving facility guaranteed by the Company and its subsidiaries other than the borrowers and Constellation Energy Partners Management, LLC (the “Excluded Subsidiary”). At December 31, 2013, the borrowing base under the Borrowing Base Facility was $115.0 million, an increase from the borrowing base of $90.0 million at December 31, 2012. With outstanding borrowings of $92.0 million and letters of credit of $1.3 million, $21.7 million was available for additional borrowings at December 31, 2013,
	Material terms of the Borrowing Base Facility include the following:
	Covenants. The Borrowing Base Facility contains affirmative and negative covenants that are customary for transactions of this type, including financial covenants that prohibit the Company and any of its subsidiaries (other than the Excluded Subsidiary) from:
	•permitting the ratio of consolidated current assets of the Company and its subsidiaries (excluding the Excluded Subsidiary) to consolidated current liabilities, after certain adjustment, at any fiscal quarter-end to be less than or equal to 1.0 to 1.0;
	•permitting the Company’s interest coverage ratio (ratio of consolidated EBITDAX (as defined in the Borrowing Base Facility) to consolidated interest charges) at any fiscal quarter-end to be less than or equal to 3.0 to 1.0 measured on a trailing four quarter basis; and
	•permitting the Company’s leverage ratio (ratio of consolidated funded debt to consolidated EBITDAX for the four fiscal quarters ending on the applicable fiscal quarter-end) to be greater than to 3.5 to 1.0.
	Interest Rate. LIBOR plus 2.50% to 3.25% or, at the borrowers’ option, Base Rate (as defined) plus 1.5% to 2.25%, in each case depending on utilization. The interest rate on outstanding borrowings on December 31, 2013 was 3.17%.
	Maturity Date. December 20, 2016.
	Borrowing Base Redetermination. Borrowing base redeterminations by the lenders will be effective every May 1st and November 1st until maturity taking into account the value of MidContinent’s proved reserves. In addition, during each period between scheduled redeterminations of the borrowing base, the borrowers and the administrative agent, respectively, have the right to initiate a redetermination of the borrowing base between each scheduled redetermination, provided that no more than two such redeterminations may occur in a 12-month period. In addition, upon a material disposition of assets and a material acquisition of oil and gas properties, and in certain other limited circumstances, the borrowing base will or may be redetermined. If the borrowing base is reduced in connection with a redetermination, the borrowers can elect to either repay the entire deficiency within 30 days, repay the deficiency in six equal monthly installments, or contribute additional properties to increase the value of the collateral to support the prior borrowing base.
	Payments. The aggregate principal amount of all outstanding revolving loans is required to be repaid on the maturity date. The borrowers are required to make a mandatory prepayment upon the occurrence of any of the following events: (a) a material disposition of oil and gas properties; (b) a change of control; (c) the existence of a borrowing base deficiency; (d) a sale of assets whose proceeds exceed 5% of the borrowing base then in effect; (e) the issuance or incurrence of indebtedness by any loan party not otherwise permitted under the Borrowing Base Facility; and (f) certain equity issuances. Interest payments are due (i) at the end of each LIBOR interest period, but in no event less frequently than quarterly in the case of LIBOR loans or (ii) quarterly in the case of Base Rate loans.
	Security Interest. The Borrowing Base Facility is secured by a first lien on substantially all of the assets of the Company and its subsidiaries other than the Excluded Subsidiary and its assets.
	Events of Default. Events of default are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts within three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, non-appealable judgment in a material amount is entered against a borrower or its affiliate, ERISA violations, invalidity of loan documents, dissolution, collateral impairment, existence of any borrowing base deficiency beyond any permitted grace periods, and change of control.
	The Company’s leverage ratio at December 31, 2013 was slightly greater than the allowed 3.5 to 1.0. The Company has obtained a waiver of noncompliance as of December 31, 2013 from the required lenders under the Borrowing Base Facility. The Company was in compliance with all other financial covenant ratios as of December 31, 2013.
	QER Loan
	The QER Loan was a former credit facility collateralized by a first priority lien on all the assets of PostRock Eastern Production, LLC, formerly named Quest Eastern Resource LLC (“QER”). In connection with the restructuring of the Company’s credit facilities in 2010, the Company entered into an asset sale agreement with RBC that allowed the Company to sell QER, or its assets and, in the event the proceeds were not adequate to repay the QER Loan in full, the Company agreed to pay a portion of such shortfall in cash, stock or a combination thereof.
	As discussed in Note 3, the Company sold certain Appalachian Basin oil and gas properties to MHR in three phases that closed in December 2010, January 2011 and June 2011. Included in the $44.6 million total was approximately $41.6 million representing the purchase price of assets owned by QER pledged as collateral under the QER Loan. From the sale proceeds, QER made payments to the lender, RBC, in the amount of $21.2 million in December 2010, $9.3 million in January 2011 and $4.3 million in June 2011. Concurrent with the June 2011 payment and pursuant to the terms of the asset sale agreement with RBC, the Company fully settled the outstanding balance of the QER Loan of approximately $843,000 by issuing 141,186 shares of its common stock with a fair value of $744,000 to RBC. The settlement also included the future remittance of a portion of the sale proceeds scheduled to be released from the escrow in June 2012. In June 2012, $5.7 million of the escrowed proceeds was released to the Company, of which $1.3 million was retained by the Company while $4.4 million was paid to RBC, representing the final payment in connection with the QER Loan. Included in the amount released to the Company was a recovery by the Company of the $843,000 payment to RBC made in June 2011.
	The settlement of the QER Loan was facilitated by the restructuring of a prior loan that met the criteria under accounting guidance to be classified as a troubled debt restructuring. The Company had previously recorded gains on debt restructuring related to the QER Loan of $2.9 million in 2010 and $1.6 million in 2011. The gain in 2011 included $799,000 of accrued interest that was forgiven at the time the balance of the loan was settled. As a result of the Company’s final evaluation of all payments made to RBC in connection with the QER Loan, an additional gain on debt restructuring of $255,000 was recorded in 2012. These gains are reflected as a “gain on forgiveness of debt” in the consolidated statement of operations.
	Deferred Financing Costs
	In connection with the closing of the Borrowing Base Facility on December 20, 2012, the Company incurred $1.7 million in financing costs that were capitalized and will be amortized over the four-year life of the facility. In conjunction with the closing of the Borrowing Base Facility, the Company’s prior credit facility was settled and $1.2 million in remaining unamortized deferred financing costs associated with the prior facility was written off.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes [Abstract]	'
Income Taxes	'
	Note 11—Income Taxes
	The Company has not recorded any provision or benefit for income taxes for the years ended December 31, 2011, and 2012. For 2013, the Company has recorded a tax expense of $180,000. During 2013 the Company settled an IRS exam relating to the 2011 tax year which resulted in current tax expense of $30,000. The Company also recorded $70,000 of tax expense related to the current tax year. All of the tax expense recorded in 2013 is alternative minimum tax, which creates an alternative minimum tax credit carryforward.  The Company has recorded a valuation against the alternative minimum tax credit carryforward.
	A reconciliation of federal income taxes at the statutory federal rates to our actual provision for income taxes is as follows:
		Year Ended December 31,
		2011		2012		2013
		(in thousands)
	Income tax expense (benefit) at statutory rate	$	7,011	$	-16,650	$	-3,100
	State income tax expense (benefit), net of federal		647		958		19
	Effect of the Recombination		—		—		—
	2011 IRS Settlement		—		—		30
	Other		2,942		1,650		496
	IRC Section 382 limitation		-2,135		30,491		2,575
	Change in valuation allowance		-8,465		-16,449		160
	Total tax expense (benefit)	$	—	$	—	$	180
	Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. Based on the negative evidence that existed at each reporting period, the Company recorded a full valuation allowance against its net deferred tax asset at December 31, 2011, 2012, and 2013.
	Deferred tax assets and liabilities at December 31, 2012 and 2013 were as follows:
		Year Ended December 31,
		2012		2013
		(in thousands)
	Current deferred income tax assets
	Unrealized loss for commodity derivative recorded for book, not for tax	$	1,658	$	722
	Accrued liabilities		1,047		1,038
	Allowance for bad debts		72		72
	Other		630		277
	Total current deferred income tax assets		3,407		2,109
	Noncurrent deferred income tax assets
	Unrealized loss for commodity derivative recorded for book, not for tax		983		669
	Partnership basis differences		6,037		6,287
	Property and equipment		45,733		37,849
	Asset retirement obligations		1,871		2,173
	Net operating loss carryforwards		18,459		14,943
	Other carryforwards		1,516		2,264
	Total noncurrent deferred income tax assets		74,599		64,185
	Total deferred income tax assets		78,006		66,294
	Current deferred income tax liabilities
	Unrealized gain for commodity derivative recorded for book, not for tax		-11,905		-20
	Other		—		—
	Total current deferred income tax liabilities		-11,905		-20
	Noncurrent deferred income tax liabilities
	Unrealized gain for commodity derivative recorded for book, not for tax		-407		-420
	Total noncurrent deferred income tax liabilities		-407		-420
	Total deferred income tax liabilities		-12,312		-440
	Net deferred income tax assets		65,694		65,854
	Valuation allowance		-65,694		-65,854
	Total deferred tax asset (liability)	$	—	$	—
	The Company has net operating loss (“NOL”) carryforwards that are available to reduce future U.S. taxable income. If not utilized, such carryforwards will expire from 2025 through 2033.
	The Company’s ability to utilize NOL carryforwards to reduce future federal taxable income and federal income tax of the Company is subject to various limitations under Internal Revenue Code (“IRC”) Section 382. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock of PostRock during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of PostRock. The Company experienced ownership changes within the meaning of IRC Section 382 on November 14, 2005, March 5, 2010, and September 21, 2010. The Company has NOL carryforwards of approximately $237 million at December 31, 2013 that are available to reduce future U.S. taxable income in certain circumstances. At December 31, 2013,  $228 million of federal NOL carryforwards are subject to the IRC Section 382 limitation and it is anticipated that $210 million of these federal NOL carryforwards will expire unused due to the IRC Section 382 limitation. As a result, only $27 million of federal NOL carryforwards have been recorded as a deferred tax asset. The limitation does not result in a current federal tax liability for the period ended December 31, 2013.
	In addition to the restrictions imposed on the Company’s NOL carryforwards under IRC Section 382, the Company also had a net unrealized built-in loss in its assets at the date of the ownership changes. IRC Section 382 generally restricts the Company’s ability to utilize any recognized built-in losses (“RBILs”) which are recognized during the 5-year period following an ownership change. The Company has recognized tax depreciation and depletion and tax losses on the disposition of its built-in loss assets during 2010, 2011, 2012 and 2013 of approximately $96.1 million. Of this amount, only $3.5 million was allowed to be deducted in the year incurred. The remaining RBILs of $92.6 million are allowed to be carried forward in a manner similar to NOLs, subject to limitation under IRC Section 382. It is anticipated that approximately $89.4 million of these RBIL carryforwards will expire unused due to the IRC Section 382 limitation. As a result, only $3.2 million of RBILs have been recorded as a deferred tax asset.
	FASB ASC 740-10 provides guidance for recognizing and measuring uncertain tax positions. Based upon the provision of FASB ASC 740-10, the Company did not record any amounts for uncertain tax benefits upon adoption of the standard and has no amounts recorded for uncertain tax benefits at December 31, 2013. Accordingly, there has been no change in unrecognized tax benefits during the year. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. Tax years ended December 31, 2010, 2011 and 2012 remain open for examination by the relevant taxing authorities. In addition, the Company’s tax returns for the tax years ended May 31, 2000, through December 31, 2009, can be examined and adjustments made to the amount of net operating losses flowing from those years into an open tax year. However, no assessment of income tax may generally be made for those years on which the statute has closed. The Company’s policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense.

Redeemable_Preferred_Stock_and

Redeemable Preferred Stock and Warrants	12 Months Ended
	Dec. 31, 2013
Redeemable Preferred Stock and Warrants [Abstract]	'
Redeemable Preferred Stock and Warrants	'
	Note 12—Redeemable Preferred Stock and Warrants
	On September 21, 2010, the Company issued to White Deer Energy L.P. and its affiliates (“White Deer”)  6,000 shares of the Company’s Series A Cumulative Redeemable Preferred Stock (the “Series A Preferred Stock”), 190,476.19 shares of its Series B Voting Preferred Stock (the “Series B Preferred Stock”) and warrants to purchase 19,047,619 shares of the Company’s common stock. The preferred stock and warrants were issued in exchange for $60 million. During 2012, the Company issued additional shares of Series A Preferred Stock and warrants to White Deer in two separate transactions. The first transaction, which closed in August 2012, included 600 shares of Series A Preferred Stock with $6.0 million initial liquidation preference along with warrants to purchase 3,076,923 shares of common stock at an exercise price of $1.95 a share. These securities were issued for proceeds of $6.0 million. The second transaction, which closed in December 2012, included 650 shares of Series A Preferred Stock with $6.5 million initial liquidation preference along with warrants to purchase 4,577,464 shares of common stock at an exercise price of $1.42 a share. These securities were issued for proceeds of $6.5 million. The terms of the Series A Preferred Stock and warrants issued in 2012 are substantially the same as those in White Deer’s original September 2010 investment except as discussed below.
	The investments discussed above were recognized on the Company’s consolidated balance sheet based on the relative fair values of the Series A Preferred Stock and the warrants allocated to the proceeds. The allocation results in an increase to the Company’s temporary equity related to the Series A Preferred Stock and an increase to additional paid in capital related to the warrants issued.
	The Series A Preferred Stock is entitled to a cumulative dividend of 12% per year on its liquidation preference, compounded quarterly. The liquidation preference will increase by the amount of dividends paid in kind. Changes in the liquidation value are disclosed in the table below. The Company is not required to pay cash dividends until December 31, 2014. Any dividends prior to that time not paid in cash will accrue as additional liquidation preference. Subsequent to December 31, 2014, dividends are required to be paid in cash, subject to the legal availability of funds for the declaration and payment thereof, and any payment default after that date will increase the accrual of the additional liquidation preference during the default period to 14%. The Company is required to redeem the Series A Preferred Stock on March 21, 2018, at 100% of the liquidation preference. From and after one year from the issuance date until such mandatory redemption date, the Company will have the option to redeem all or a specified minimum portion of the Series A Preferred Stock at 110% of the liquidation preference. The holders of the Series A Preferred Stock have the right to require the Company to purchase their shares on the occurrence of specified change in control events at 110% of the liquidation preference. In the case of specified defaults by the Company, including the failure to pay dividends for any quarterly period after December 31, 2014, and until the defaults are cured, the holders of the Series A Preferred Stock have the right to appoint two additional directors to the Board of Directors. The Series A Preferred Stock does not vote generally with the common stock, but has specified approval rights with respect to, among other things, changes to the Company’s certificate of incorporation that affect the Series A Preferred Stock, cash dividends on the common stock or other junior stock, redemptions or repurchases of common stock or other capital stock, increases in the size of the Board of Directors, changes to specified debt agreements and changes to the Company’s business.
	With respect to the Series A Preferred Stock issued on September 21, 2010, prior to December 31, 2014, if dividends are not paid in cash on a dividend payment date, the Company will issue additional warrants exercisable for a number of shares of common stock equal to the amount of dividends that are not paid on that dividend payment date divided by the closing price of the common stock on the trading date immediately preceding the dividend payment date. The exercise price of the warrants will be such closing price. The warrants, including any additional warrants, are exercisable for 90 months following the applicable issuance date. Each warrant is coupled, and may only be transferred as a unit, with a number of one one-hundredths of a share, or a “fractional share,” of Series B Preferred Stock equal to the number of shares of common stock purchasable upon exercise of the warrant. The warrants and the Series B Preferred Stock may not be transferred separately. If and when the warrant is exercised, the holder of the warrant will be required to deliver to the Company, as part of the payment of the exercise price, a number of fractional shares of Series B Preferred Stock equal to the number of shares of common stock purchased upon such exercise. The holders of the warrants have the right to pay the exercise price in cash, by electing a cashless exercise (whereby the holder will receive the excess of the market price of the common stock over the exercise price in shares of common stock valued at the market price) or by tendering shares of Series A Preferred Stock with a liquidation preference equal to the exercise price. If the market price of the common stock exceeds 300% of the exercise price for a specified period of time and other conditions are satisfied, the Company may require the holders of the warrants to exercise warrants to purchase up to 50% of shares covered thereby, but in the aggregate not less than 750,000 shares or more than 50% of the trading volume of the common stock over the preceding 20 trading days.
	With respect to the warrants issued in conjunction with the Series A Preferred Stock in August 2012 and December 2012, including those that may be issued on future pay-in-kind dividends on this preferred stock, the terms are otherwise similar to those issued in September 2010 except they are not coupled with a fractional share of Series B Preferred Stock (and therefore have no voting right attached) and all of those warrants will have an exercise price of $1.95 a share and $1.42 a share, respectively, rather than the market price at the time of issuance.
	The holders of Series B Preferred Stock are entitled to vote in the election of directors and on all other matters submitted to a vote of the holders of common stock of the Company, with the holders of Series B Preferred Stock and the holders of common stock voting together as a single class. Each fractional share of Series B Preferred Stock has one vote. The voting rights of each share of Series B Preferred Stock may not be exercised by any person other than the holder of the warrant that is part of the unit with such share or fractional share and will expire on the expiration date of such warrant. The Series B Preferred Stock has no dividend rights and a nominal liquidation preference. With respect to the votes applicable to the Series B Preferred Stock, the holders of the Series B Preferred Stock and their affiliates are limited to 45% of the votes applicable to all outstanding voting stock; such holders and their affiliates may vote any shares of common stock held by them without regard to that limit.
	When the Company accrues dividends on its Series A Preferred Stock on a quarterly dividend payment date, it records the increase in liquidation preference and the issuance of additional warrants by allocating their relative fair values to the amount of accrued dividends. The allocation results in an increase to the Company’s temporary equity related to the Series A Preferred Stock and an increase to additional paid in capital related to the additional warrants issued.
	The Series A Preferred Stock has been recorded outside of permanent equity and liabilities, in the Company’s consolidated balance sheet because the settlement provisions of the warrants allow White Deer to “net exercise” the warrants by requiring the Company to repay the Series A Preferred Stock at the liquidation preference to offset the strike price of the warrants that would otherwise be due from White Deer in cash. Absent this provision, the Series A Preferred Stock would have met the definition of mandatorily redeemable preferred stock under FASB ASC 480 Distinguishing Liabilities from Equity which would have required recognition as a liability. This provision allows the Series A Preferred Stock to effectively be convertible to common stock at the election of White Deer. In the event that White Deer exercises the warrants without net-exercising the Series A Preferred Stock back to the Company as payment for the strike price of the warrants, the Company will be required to reclassify a proportionate amount of Series A Preferred Stock from temporary equity to liabilities as that portion of the Series A Preferred Stock is no longer convertible to common stock and thus has become mandatorily redeemable.
	In December 2013, the Company closed on a Warrant Exchange Agreement with White Deer pursuant to which the Company issued to White Deer  1,123,981 shares of its common stock with a fair value of $1.5 million in exchange for the following securities of the Company held by the White Deer: warrants exercisable for 22,241,333 shares of common stock (the “Warrants”) together with a like number of one one-hundredths of a share of Series B Voting Preferred Stock that were issued as a unit with the Warrants (collectively, the “Warrant Exchange”). The Warrants had exercise prices ranging from $2.80 to $6.39 per share, with a weighted average exercise price of $3.23 per share. The number of shares issued was calculated based on the Black-Scholes model. With the exchange and retirement of the Warrants, the likelihood that the portion of the liquidation preference on the Series A Preferred Stock will be utilized for a cashless exercise of the Warrants ceases to exist. Accordingly, that portion of the Series A Preferred Stock liquidation preference is no longer convertible to common stock and now becomes mandatorily redeemable.  Pursuant to applicable accounting guidance, the Company reclassified $64.5 million out of temporary and permanent equity into liabilities representing the fair value of the Series A Preferred Stock liquidation preference that became mandatorily redeemable. No gain or loss was recognized as a result of the reclassification. The fair value of the reclassified mandatorily redeemable portion was determined by discounting the cash flows over the remaining life of the securities utilizing a LIBOR interest rate corresponding to the applicable maturity and a risk premium of 13.7%, which was based on companies with similar leverage ratios to PostRock. The Company has classified this valuation under Level 2 of the fair value hierarchy. Subsequent to the reclassification, dividends and accretion related to the reclassified Series A Preferred Stock will be recorded as interest expense for which $497,000 was recognized for the year ended December 31, 2013. However, when dividends on the mandatorily redeemable portion are paid in kind in the future through an increase in liquidation preference and additional issuance of warrants, the increase in liquidation preference is recorded to temporary equity rather than liabilities as it still retains the potential of being used for a cashless exercise of the warrants and hence deemed to be conditionally redeemable.
	The following table summarizes changes in the Series A Preferred Stock and associated warrants:
		Carrying Value		Carrying Value		Number of
		of Series A		of Series A		Outstanding		Liquidation Value		Number of	Weighted Average
		Preferred Stock in		Preferred Stock		Series A		of Series A		Outstanding	Exercise Price of
		Temporary Equity		in Liabilities		Preferred Shares		Preferred Stock		Warrants	Warrants
		(in thousands except share, warrant and per unit data)
	31-Dec-10	$	50,622	$	—	6,000		$	61,980	19,584,205	$	3.16
	Accrued dividends		4,534		—	—			7,779	1,982,040		3.92
	Accretion		1,580		—	—			—	—		—
	31-Dec-11		56,736		—	6,000			69,759	21,566,245		3.23
	Issuance		8,428		—	1,250			12,500	7,654,387		1.63
	Accrued dividends		5,750		—	—			9,083	5,115,782		1.78
	Accretion		2,238		—	—			—	—		—
	31-Dec-12		73,152		—	7,250			91,342	34,336,414		2.66
	Accrued dividends		7,479		—	—			11,047	8,066,270		1.42
	Accrued dividends recorded as interest		—		—	—			417	—		—
	Warrant Exchange		-60,086		64,443	—			—	-22,241,333		3.23
	Accretion		3,283		80	—			—	—		—
	31-Dec-13	$	23,828	$	64,523	7,250		$	102,806	20,161,351	$	1.54
	The following table summarizes changes to additional paid in capital (“APIC”) as a result of warrants issued to White Deer:
		Year Ended December 31,
		2011		2012		2013
		(in thousands)
	Warrants issued in conjunction with issuance of Series A Preferred Stock	$	—	$	4,071	$	—
	Warrants issued in conjunction with paid-in-kind dividends		3,245		3,334		3,984
	Total change in APIC due to warrants issued	$	3,245	$	7,405	$	3,984

Equity_and_Earnings_Per_Share

Equity and Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Equity And Earnings Per Share [Abstract]	'
Equity and Earnings Per Share	'
	Note 13—Equity and Earnings per Share
	Restricted share and stock option grants to employees and non-employee directors is governed by PostRock’s 2010 Long-Term Incentive Plan (the “LTIP”) of which 10,850,000 shares have been authorized for awards.
	The Company’s employee share based grants, including restricted shares and options, have generally vested 33% a year for three years or have vested in one year when awarded in conjunction with the Company’s annual bonus program. Share based grants to non-employee directors have generally vested immediately or in one year.
	A summary of changes in the non-vested restricted shares or share units for PostRock and its Predecessors for the periods presented is below:
		Number of Non-Vested		Weighted Average Grant
		Restricted Shares		Date Fair Value
	Non-vested restricted shares at December 31, 2010	375,358		$	4.83
	Granted	487,500			2.90
	Vested	-80,554			5.91
	Forfeited	-203,094			5.08
	Non-vested restricted shares at December 31, 2011	579,210			3.33
	Granted	1,295,112			2.01
	Vested	-275,900			3.23
	Forfeited	-118,856			3.76
	Non-vested restricted shares at December 31, 2012	1,479,566			2.16
	Granted	641,902			1.75
	Vested	-452,529			2.79
	Cancelled/Forfeited (1)	-1,053,673			1.79
	Non-vested restricted shares at December 31, 2013	615,266		$	1.89
	____________
	(1)  787,414 shares were cancelled with an associated accelerated stock compensation expense of approximately $500,000.
	At December 31, 2013, total unrecognized stock-based compensation expense related to non-vested restricted shares was $444,000, which is expected to be recognized over a weighted average period of approximately 1.23 years while 7,208,111 shares were available under the LTIP for future stock awards and options.
	Stock Options—The LTIP also provides for the granting of options to purchase shares of PostRock’s common stock. The Company has in the past granted stock options to employees and non-employees. Option grants under the LTIP expire 5-6 years following the date of grant.
	A summary of changes in stock options outstanding for PostRock and its Predecessors is presented below:
				Weighted Average			Weighted Average
		Stock options		Exercise Price per			Grant Date Fair
				Option			Value per Option
	Options outstanding at December 31, 2010	567,050		$	4.17
	Granted	799,400			3.63		$	2.15
	Exercised (1)	-20,000			3.29
	Forfeited or expired	-289,600			4.07
	Options outstanding at December 31, 2011	1,056,850			3.59
	Granted	1,303,653			1.80			1.07
	Forfeited or expired	-190,220			4.30
	Options outstanding at December 31, 2012	2,170,283			2.45
	Granted	584,949			1.77			0.89
	Forfeited or expired	-448,813			1.92
	Options outstanding at December 31, 2013	2,306,419			2.38
	Exercisable
	Options exercisable at December 31, 2011	310,922		$	5.57
	Options exercisable at December 31, 2012	467,189			4.10
	Options exercisable at December 31, 2013	989,037			3.03
	____________
	(1)The Company received $66,000 upon exercise of these options which had a total intrinsic value of $34,000 at the exercise dates.
	The weighted average remaining term of options outstanding and options exercisable at December 31, 2013, was 3.52 and 3.08 years, respectively. Both options outstanding and options exercisable at December 31, 2013, had aggregate intrinsic values of nil.
	The Company determines the fair value of stock option awards using the Black-Scholes option pricing model. As the Company does not have sufficient historical exercise or post-vesting termination experience, the Company currently uses an expected option term of four years, which is the average of the vesting term and the original contractual term.  The expected forfeiture rate was estimated based upon historical forfeiture experience. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical and implied volatility of peer companies. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a 12-month average dividend yield.
	The Company used the following assumptions to estimate the fair value of stock options granted during the years ending December 31, 2011, 2012 and 2013.
		2011				2012				2013
	Expected option life-years		6-May				5				4
	Volatility		74.4 - 77.0	%			74.3 - 76.1	%			64.0 - 82.7	%
	Risk-free interest rate		0.9 - 2.0	%			0.9 - 1.3	%			0.6 - 1.4	%
	Dividend yield		—				—				—
	Fair value per share	$	1.43 - 4.53			$	0.87 - 1.88			$	0.82 - 1.03
	At December 31, 2013, there was $665,000 of total unrecognized compensation cost related to stock options which is expected to be recognized over a weighted average period of 1.27 years.
	Total share-based compensation covering stock awards and options is included in general and administrative expense on the consolidated statement of operations and is disclosed below for the periods presented:
		Total Share
		Based
		Compensation
		Expense
		(in thousands)
	Year Ended December 31, 2011	$	1,258
	Year Ended December 31, 2012		2,224
	Year Ended December 31, 2013		3,177
Income/(Loss) per Share — A reconciliation of the denominator (number of shares) used in the basic and diluted per share calculations for the periods indicated is as follows:
	Year Ended December 31,
	2011		2012		2013
Denominator for basic earnings per share (1)	8,785,551		13,595,843		25,068,574
Effect of potentially dilutive securities
Unvested share-based awards	127,600		—		—
Warrants	6,089,339		—		—
Stock options	47,230		—		—
Denominator for diluted earnings per share	15,049,720		13,595,843		25,068,574
Securities excluded from earnings per share calculation
Unvested share-based awards	14,998		149,988		—
Antidilutive stock options	1,056,850		2,170,283		2,306,419
Warrants	1,830,464		33,086,615		17,929,512
____________
(1)Includes vested common shares in the Company’s deferred compensation plan and vested deferred restricted stock units, both of which will deliver shares to participants at a later date. Although shares have not been delivered on these awards, all conditions for issuance and delivery have been met. Pursuant to FASB ASC 260-10-45-13, such shares are to be included in the denominator in calculating basic earnings per share.
Common Stock Issuance—During 2012 and 2013, the Company issued common stock to generate capital, fund its 401K and deferred compensation plans (Note 18), fund property acquisitions (Note 3) and to retire outstanding warrants (Note 12). Equity issuances intended to raise capital are discussed below. Proceeds from these transactions were used for debt repayment and for other general corporate purposes.
During 2012, the Company issued common stock to White Deer in three separate transactions as disclosed in the table below.
	Feb-12			Aug-12			Dec-12
Gross proceeds (in thousands)	$	7,500		$	6,000		$	6,500
Common shares sold		2,180,233			3,076,923			4,577,464
The Company has an effective $100 million universal shelf registration statement under which it has been selling common shares pursuant to an at-the-market issuance sales agreement as disclosed in the table below.
	Year Ended December 31,
	2012			2013
Gross proceeds (in thousands)	$	724		$	4,076
Common shares sold		446,098			2,592,313

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies [Abstract]	'
Commitments and Contingencies	'
	Note 14—Commitments and Contingencies
	Litigation—The Company is subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting its business. It records a liability related to its legal proceedings and claims when it has been determined that it is probable that it will be obligated to pay and the related amount can be reasonably estimated. The Company currently believes that there are no pending legal proceedings in which it is currently involved which have a reasonable possibility of materially affecting its financial position, results of operations or cash flows in an adverse manner.
	The Company had been sued in royalty owner lawsuits filed in Oklahoma and Kansas. In Oklahoma, suits by a group of individual royalty owners and by a putative class representing all remaining royalty owners were filed in the District Court of Nowata County, Oklahoma. Generally, the lawsuits alleged that the Company wrongfully deducted post-production costs from the plaintiffs’ royalties and engaged in self-dealing agreements resulting in a less than market price for the gas production. The Company denied the allegations. Settlements were reached in each of the cases, and upon final approval from the Court, the Company paid $5.6 million in settlement of the Oklahoma suits in July 2011.
	The Kansas lawsuit was a putative class action filed in the United States District Court for the District of Kansas, brought on behalf of all the Company’s royalty owners in that state. Plaintiffs generally alleged that the Company failed to properly make royalty payments by, among other things, charging post-production costs to royalty owners in violation of the underlying lease contracts, paying royalties based on sale point volumes rather than wellhead volumes, allocating expenses in excess of the actual and reasonable post-production costs incurred, allocating production costs and marketing costs to royalty owners, and making royalty payments after the statutorily prescribed time for doing so without paying interest thereon. We denied plaintiffs’ claims. The parties reached a settlement and on December 30, 2011, the Court entered an order certifying a class for settlement purposes consisting of all current and former PostRock royalty and overriding royalty owners, approving the parties’ settlement and dismissing the action. The settlement included a payment of $3.0 million that was made in January 2012, and a payment of $4.5 million which was made in December 2012, for a total of $7.5 million.
	In connection with their criminal convictions, in November 2010, Jerry Cash and David Grose were ordered to pay the Company restitution in the sums of $5 million and $1 million, respectively. The Company intends to continue to pursue recovery of the restitution obligations.
	Additionally, see Note 8 – Equity Investment for discussion on litigation with CEP. Litigation reserve expense was $11.6 million for the year ended December 31, 2011, while no litigation reserve expense was recorded for the years ended December 31, 2012 and 2013, respectively.
	Environmental Matters—At December 31, 2012 and 2013, there were no known environmental or regulatory matters related to our operations which are reasonably expected to result in a material liability to us. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is difficult to reasonably quantify future environmental related expenditures.
	Operating Lease Commitments—The Company has lease agreements to obtain natural gas compressors as and when required. Terms of the leases on the gas compressors call for a minimum obligation of one year and are month to month thereafter. In addition, the Company also has operating leases for office space, warehouse facilities, and office equipment expiring in various years through 2018.
	Future minimum rental payments under all non-cancelable operating leases at December 31, 2013, were as follows:
	Year ending December 31,	(in thousands)
	2014	$	3,558
	2015		2,468
	2016		847
	2017		373
	2018		10
	Thereafter		—
	Total minimum lease obligations	$	7,256
	Total rental expense under cancelable and non-cancelable operating leases was $13.6 million, $12.4 million and $10.8 million for the years ended December 31, 2011,  2012 and 2013, respectively.

Impairment_of_Oil_and_Gas_Prop

Impairment of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2013
Impairment of Oil and Gas Properties [Abstract]	'
Impairment of Oil and Gas Properties	'
	Note 15—Impairment of Oil and Gas Properties
	At the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the full cost ceiling, computed as the sum of the estimated future net revenues from proved reserves using twelve-month average prices discounted at 10%, and adjusted for related income tax effects (ceiling test). Under full cost accounting rules, any ceiling test write-down of oil and natural gas properties may not be reversed in subsequent periods. Since the Company does not designate its derivative financial instruments as hedges, it is not allowed to use the impacts of the derivative financial instruments in its ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in the Company’s ceiling test results.
	The base for the Company’s spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. At the end of the third and fourth quarters of 2012, the ceiling test computation resulted in the carrying costs of the Company’s unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the present value of future net revenues. As a result of this difference, the Company recorded ceiling test impairments of its oil and gas properties of $5.9 million for the year ended December 31, 2012. There were no ceiling test impairments for the years ended December 31, 2011 and 2013. The Company may face further ceiling test write-downs in future periods, depending on the level of commodity prices, drilling results and well performance.
	The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, production and changes in economics related to the properties subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2013
Discontinued Operations [Abstract]	'
Discontinued Operations	'
	Note 16—Discontinued Operations
	The Company previously owned an interstate natural gas pipeline in its PostRock KPC Pipeline, LLC (“KPC”) subsidiary. On September 28, 2012, the Company, PostRock Energy Services Corporation, a wholly owned subsidiary of the Company (“Seller”), and KPC entered into and simultaneously closed a Purchase Agreement (the “Purchase Agreement”) with MV pursuant to which the Seller sold all the equity of KPC to MV for a gross purchase price of $53.5 million. After an adjustment for working capital as set forth in the Purchase Agreement, the Company received $53.4 million in proceeds at closing. MV also agreed to make additional payments of $1.0 million for each of the next four years if qualified EBITDA (as defined in the Purchase Agreement) of KPC for that year exceeds a target amount. Determination of qualified EBITDA for the first year is due from MV no later than May 30, 2014. KPC owns a 1,120 mile interstate natural gas pipeline that transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City, which formerly comprised the Company’s pipeline segment.
	The carrying value of KPC’s net assets sold was $57.0 million which resulted in a loss on sale of $5.4 million. The loss on sale included $1.9 million in closing-related costs comprised of $1.0 million in legal, professional, and investment banking fees, $505,000 of severance and $350,000 in site cleanup costs. The operating results of KPC are classified as discontinued operations and are presented in a separate line in the consolidated statement of operations for all periods presented. Prior to the classification as a discontinued operation, the Company had reported this business as a separate segment under the heading “Pipeline.”
	The following table discloses the results of discontinued operations related to KPC:
		Year Ended December 31,
		2011		2012
		(in thousands)
	Interstate pipeline revenue	$	11,183	$	8,934
	Pipeline expense		-5,219		-2,825
	Depreciation and amortization		-3,574		-2,537
	Gain (loss) on disposal of assets (1)		3		-5,437
	General and administrative expenses		-1,194		-945
	Interest expense		-556		-45
	Income from discontinued operations before income taxes		643		-2,855
	Income taxes		—		—
	Total income (loss) from discontinued operations	$	643	$	-2,855
	____________
	(1)Includes a loss of $5.4 million from the disposal of KPC.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental Cash Flow Information	'
	Note 17—Supplemental Cash Flow Information
	The following discloses certain cash and noncash transactions for the periods indicated:
		Year Ended December 31,
		2011		2012		2013
		(in thousands)
	Cash paid for interest	$	8,623	$	7,292	$	2,780
	Cash paid for income taxes		—		—		100
	Non-cash investing activity
	Common stock issued for purchase of equity investment		4,100		—		—
	Common stock issued for purchase of oil and gas properties		—		—		6,728
	Common stock issued to fund 401K and deferred compensation plans		—		—		931
	Common stock issued to repurchase and retire outstanding warrants		—		—		1,528
	Warrants issued for purchase of equity investment		518		—		—
	Equity securities received on the sale of oil and gas properties		5,875		—		—
	Property additions financed through accounts payable and accrued liabilities		830		239		1,010
	Additions to property and equipment by recognizing asset retirement obligations		4,067		159		1,099
	Non-cash financing activity
	Reduction of debt through conveyance of financial securities received from sale of oil and gas properties		5,729		—		—
	Reduction of debt through issuance of common stock		843		—		—
	Issuance of preferred stock and warrants in lieu of cash dividends		7,779		9,083		11,464
	Accretion of discount on redeemable preferred stock reflected in interest expense		—		—		80
	Accretion of discount on redeemable preferred stock		1,580		2,238		3,283

Profit_Sharing_And_Deferred_Co

Profit Sharing And Deferred Compensation Plan	12 Months Ended
	Dec. 31, 2013
Profit Sharing And Deferred Compensation Plan [Abstract]	'
Profit Sharing And Deferred Compensation Plan	'
	Note 18—Profit Sharing and Deferred Compensation Plan
	401K plan — Substantially all of the Company’s employees are eligible to participate in a profit sharing plan under Section 401(k) of the Internal Revenue Code (the “401K plan”). In 2013, the Company contributed three percent of employees’ annual compensation regardless whether contributions were made by the employee. The Company would also match 100% of employee contributions in excess of three percent up to a total of six percent of annual compensation. Employees vest 33% in Company contributions in their first year of service, 67% in their second year of service and 100% in their third year of service. Prior to 2013, employer matching contributions to the 401K plan were made in cash. Beginning in 2013, employer matching contributions to the 401K plan may be made in Company common stock. In general, the Company issues common stock to fund its matching contributions although, from time to time, purchases of common stock on the open market by the 401K plan trust may occur if funds are available as a result of forfeitures.  During the year ended December 31, 2013, 404,805 shares of common stock were contributed to the 401K plan, of which 325,005 shares were issued by the Company, and 79,800 shares were purchased by the 401K plan trust on the open market.
	The following table presents the expense incurred by the Company related to the 401K plan which is reflected in the consolidated statements of operations as a component of general and administrative expense:
		Year Ended December 31,
		2011			2012		2013
		(in thousands)
	401(k) profit sharing plan cost	$	492		$	235	$	662
	Deferred compensation plan — Effective January 1, 2013, the Company established a deferred compensation plan that permits selected employees and members of its board to defer part or all of their eligible compensation. The following table presents the number of shares and the related fair values of common stock contributed by the Company to the deferred compensation plan in 2013. The fair value of common stock is based on the market price of the stock on the preceding day that the stock is transferred and thus deemed to be a Level 1 measurement  under the fair value hierarchy. Contributions were not made in the prior year as the plan was not in effect during that time.
			Year Ended
			31-Dec-13
			($ in thousands)
	Shares of common stock contributed			324,522
	Fair value of common stock contributed		$	473

Supplemental_Financial_Informa

Supplemental Financial Information-Quarterly Financial Data	12 Months Ended
	Dec. 31, 2013
Supplemental Financial Information-Quarterly Financial Data [Abstract]	'
Supplemental Financial Information-Quarterly Financial Data	'
	Note 19—Supplemental Financial Information—Quarterly Financial Data (Unaudited)
	Summarized unaudited quarterly financial data for 2012 and 2013 are as follows:
		Quarters Ended
		March 31,		June 30,		September 30,		December 31,
		(in thousands, except per share data)
	2012
	Total revenues	$	14,321	$	11,124	$	13,697	$	15,853
	Operating income (loss) (1)		-7,501		-10,352		-11,409		-6,649
	Net income (loss)		7,347		-18,508		-25,174		-11,237
	Net income (loss) per common share
	Basic	$	0.43	$	-1.71	$	-1.94	$	-0.89
	Diluted	$	0.37	$	-1.71	$	-1.94	$	-0.89
		Quarters Ended
		March 31,		June 30,		September 30,		December 31,
		(in thousands, except per share data)
	2013
	Total revenues	$	16,053	$	19,594	$	18,614	$	18,039
	Operating income (loss) (1)		-3,727		-2,019		-1,679		-3,873
	Net income (loss)		-7,894		6,880		-645		-7,377
	Net income (loss) per common share
	Basic	$	-0.5	$	0.13	$	-0.18	$	-0.38
	Diluted	$	-0.5	$	0.13	$	-0.18	$	-0.38
	____________
	(1)Total revenue less total costs and expenses.

Supplemental_Information_on_Oi

Supplemental Information on Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Supplemental Information on Oil and Gas Producing Activities [Abstract]	'
Supplemental Information on Oil and Gas Producing Activities	'
	Note 20—Supplemental Information on Oil and Gas Producing Activities (Unaudited)
	The supplementary oil and gas data that follows is presented in accordance with FASB ASC 932 Extractive Activities—Oil and Gas (“FASB ASC 932”),  and includes (1) capitalized costs, costs incurred and results of operations related to oil and gas producing activities, (2) net proved oil and gas reserves, and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves.
	Equity investment—At December 31, 2013, the Company owns 21.3% voting interest in CEP, a publicly traded oil and gas exploration and production company. The Company’s equity interest in CEP was 26.4% and 26.5% at December 31, 2011 and 2012, respectively. CEP utilizes the successful efforts method of accounting for its oil and gas activities. Where applicable, the disclosures required under FASB ASC 932 are made below based on the Company’s proportionate share of CEP’s oil and gas activities according to the percentages described above. Information utilized to prepare disclosures on the Company’s proportionate share of CEP is based on publicly available data. The Company has updated previously filed amounts for December 31, 2012 related to CEP as discontinued operations have now been presented in their current public filing. Since December 31, 2011 amounts were not publicly available these amounts do not reflect the changes from discontinued operations.
	Net Capitalized Costs
	Aggregate capitalized costs related to oil and gas producing activities of the Company at December 31, 2012 and 2013, are summarized as follows:
		2012			2013
		(in thousands)
	Oil and gas properties and related leasehold costs
	Proved	$	353,093		$	405,895
	Unproved		31			4,862
			353,124			410,757
	Accumulated depreciation, depletion and amortization		-245,593			-268,846
	Net capitalized costs	$	107,531		$	141,911
	Unproved properties not subject to amortization consisted mainly of leaseholds acquired through acquisitions. The Company will continue to evaluate its unproved properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.
	Aggregate capitalized costs related to oil and gas producing activities of the Company’s proportionate investment in CEP at December 31, 2012 and 2013, are summarized as follows:
		2012			2013
		(in thousands)
	Oil and gas properties and related equipment (successful efforts method)
	Proved	$	156,851		$	135,642
	Unproved		366			338
	Materials, supplies and land		402			385
			157,619			136,365
	Accumulated depreciation, depletion and amortization		-125,787			-105,481
	Net capitalized costs	$	31,832		$	30,884
	Costs Incurred
	Costs incurred for oil and gas property acquisition, exploration and development activities that have been capitalized for the years ended December 31, 2011, 2012, and 2013 are summarized as follows:
		Consolidated Entities							CEP (1)
		2011			2012		2013		2011		2012		2013
		(in thousands)
	Proved property acquisition costs (2)	$	223		$	151	$	8,023	$	-74	$	20	$	4,262
	Unproved property acquisition costs		630			52		8,567		167		47		45
	Exploration costs		—			—		—		—		—		—
	Development Costs		23,825			12,506		40,004		2,895		4,064		3,343
		$	24,678		$	12,709	$	56,594	$	2,988	$	4,131	$	7,650
	____________
	(1)Based on the Company’s pro-rata interest in CEP (disclosed above) assuming that the Company’s investment was made at the beginning of the period.
	(2)The amount is negative for CEP in 2011 as it represents a post-closing receipt from an acquisition made by CEP in December 2010.
	Results of Operations
	The revenues and expenses associated directly with the Company’s oil and natural gas producing activities are reflected in the consolidated statement of operations. All of our ongoing operations are oil and natural gas producing activities located in the United States.
	The table below presents the pro-rata results of oil and gas producing activities of the Company’s investment in CEP for the years ended December 31, 2011, 2012, and 2013 assuming that the Company’s investment was made at the beginning of the period presented.
		2011			2012		2013
		(in thousands)
	Revenues	$	27,778		$	12,330	$	9,388
	Lease operating expense		7,379			5,144		4,017
	Cost of sales and production taxes		1,343			780		864
	Exploration costs		35			—		—
	Impairment of oil and gas properties		775			29		502
	Depreciation, depletion and amortization		5,845			3,109		4,041
	Oil and Gas Reserve Quantities
	The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in estimated quantities for its proved reserves, all of which are located in the United States. Cawley, Gillespie & Associates, Inc., independent reserve engineering firm, was retained to perform the annual year-end independent evaluation of the Company’s proved reserves.
	Users of this information should be aware that the process of estimating quantities of “proved,” “proved developed” and “proved undeveloped” oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upwards or downward) to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
	The table below presents changes in proved developed and undeveloped reserves of our consolidated entities.
		Gas - Mcf		Oil - Bbls
	Proved reserves
	Balance, December 31, 2010	130,462,031		744,266
	Purchase of reserves in place	—		—
	Extensions, discoveries, and other additions	1,752,746		54,761
	Sale of reserves	-754,479		—
	Revisions of previous estimates	5,068,946		352,981
	Production	-18,309,056		-78,087
	Balance, December 31, 2011	118,220,188		1,073,921
	Purchase of reserves in place	—		—
	Extensions, discoveries, and other additions	1,867,365		617,854
Sale of reserves	—		—
Revisions of previous estimates	-34,037,402		1,095,656
Production	-16,388,878		-95,863
Balance, December 31, 2012	69,661,273		2,691,568
Purchase of reserves in place	98,822		554,892
Extensions, discoveries, and other additions	1,122,511		1,911,959
Sale of reserves	—		—
Revisions of previous estimates	30,246,006		-585,342
Production	-14,521,385		-192,474
Balance, December 31, 2013	86,607,227		4,380,603
Proved developed reserves
Balance, December 31, 2011	117,406,577		1,040,309
Balance, December 31, 2012	69,661,273		1,804,057
Balance, December 31, 2013	85,006,592		2,705,664
The table below presents the Company’s pro-rata share of changes in reserves and the amounts of proved developed reserves of CEP assuming that the Company’s investment was made as of January 1, 2011.
	Mcfe
Proved reserves
Balance, January 1, 2011	44,618,000
Purchase of reserves in place	—
Extensions, discoveries, and other additions	455,000
Sale of reserves	—
Revisions of previous estimates	11,216,000
Production	-3,138,000
Balance, December 31, 2011	53,151,000
Purchase of reserves in place	—
Extensions, discoveries, and other additions	543,000
Sale of reserves	-68,000
Revisions of previous estimates	-25,551,000
Production	-3,435,000
Balance, December 31, 2012	24,640,000
Decrease in pro rata ownership	-4,835,000
Purchase of reserves in place	1,523,000
Extensions, discoveries, and other additions	1,028,000
Sale of reserves	-10,519,000
Revisions of previous estimates	9,527,000
Production	-1,927,000
Balance, December 31, 2013	19,437,000
Proved developed reserves
Balance, December 31, 2011	40,295,000
Balance, December 31, 2012	23,850,000
Balance, December 31, 2013	16,748,000
Standardized Measure of Discounted Future Net Cash Flows
The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows at December 31, 2011, 2012 and 2013 in accordance with FASB ASC 932 which requires the use of a 10% discount rate. Future income taxes are based on year-end statutory rates. This information is not the fair market value, nor does it represent the expected present value of future cash flows of Company’s proved oil and gas reserves.
	Consolidated Entities							CEP (1)
	2011			2012		2013		2011		2012		2013
	(in thousands)
Future cash inflows	$	592,796		$	438,356	$	720,924	$	241,173	$	95,619	$	107,103
Future production costs		312,410			218,707		315,079		132,081		51,462		48,418
Future development costs		10,524			31,051		49,590		25,705		2,948		8,668
Future income tax expense		—			—		30,149		—		—		—
Future net cash flows		269,862			188,598		326,106		83,387		41,209		50,017
10% annual discount for estimated timing of cash flows		94,342			86,516		156,977		40,964		17,446		19,406
Standardized measure of discounted future net cash flows related to proved reserves	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
Standardized measure from continuing operations	$	175,520		$	102,082	$	169,129	$	42,423	$	16,021	$	30,611
Standardized measure from discontinued operations		—			—		—		—		7,742		—
Standardized measure of discounted future net cash flows related to proved gas reserves	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
____________
(1)Represents the Company’s pro-rata share of its investment in CEP.
Future cash inflows are computed by applying a first-day-of-month, twelve-month average price, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of our derivative instruments. See the following table for average oil and gas prices as of the periods indicated.
	2011			2012		2013
Crude oil price per Bbl	$	96.19		$	95.05	$	96.94
Natural gas price per MMBtu	$	4.12		$	2.76	$	3.67
The principal changes in the standardized measure of discounted future net cash flows relating to proven oil and gas properties were as follows:
	Consolidated Entities							CEP (1)
	2011			2012		2013		2011		2012		2013
	(in thousands)
Present value, beginning of period	$	159,261		$	175,520	$	102,082	$	34,765	$	42,423	$	23,763
Net changes in prices and production costs		11,876			18,071		37,826		38		-5,095		10,741
Decrease in pro rata ownership		—			—		—		—		—		-4,664
Net changes in future development costs		-1,154			-18,008		-30,462		—		—		—
Previously estimated development costs incurred		18,192			12,743		40,196		1,892		4,987		1,196
Sales of oil and gas produced, net		-32,751			-10,338		-29,604		-7,810		-10,520		-4,525
Extensions and discoveries		3,045			7,724		23,514		2,157		3,336		6,069
Purchases of reserves in-place		—			—		6,401		—		—		—
Sales of reserves in-place		-1,104			—		—		—		-391		-489
Revisions of previous quantity estimates		10,513			-38,064		49,926		11,243		-22,034		4,570
Net change in income taxes		12,037			—		-7,769		—		—		—
Accretion of discount		16,448			16,730		8,975		3,477		4,258		1,910
Timing differences and other (2)		-20,843			-62,296		-31,956		-3,339		6,799		-7,960
Present value, end of period	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
Standardized measure from continuing operations	$	175,520		$	102,082	$	169,129	$	42,423	$	16,021	$	30,611
Standardized measure from discontinued operations		—			—		—		—		7,742		—
Standardized measure of discounted future net cash flows related to proved gas reserves	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
____________
(1)Represents the Company’s pro-rata share of its investment in CEP assuming that the Company’s investment was made at the beginning of each period presented.
(2)The change in timing differences and other are related to revisions in the Company’s estimated time of production and development and the impact of changes in the relative proportion of oil versus natural gas in the Company’s total reserves.
During 2013, the Company focused its development activities on oil related projects. As a result, the proportion of oil reserves to total reserves increased from 5% at December 31, 2011, to 19% at December 31, 2012 and 23% as of December 31, 2013. Since the Company calculates the price variance on an energy equivalent basis, the change in the Company’s reserve mix coupled with the 26:1 ratio of oil price to natural gas price used in the calculation, resulted in a positive net price variance. The positive price variance is reflected under “net changes in prices and production costs” in the table above. As a positive net price variance is disclosed, existing natural gas reserves, which comprised 77% of total reserves at December 31, 2013, decreased in value due to a decrease in the average natural gas price. This decline in value of natural gas reserves is included in “timing differences and other” in the table above.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]	'
Principles of Consolidation	'
	Principles of Consolidation—These consolidated financial statements include PostRock’s and its subsidiaries’ accounts. Subsidiaries in which PostRock directly or indirectly owns more than 50% of the outstanding voting securities or those in which PostRock has effective control over are generally accounted for under the consolidation method of accounting. Under this method, a subsidiaries’ balance sheet and results of operations are reflected within the Company’s consolidated financial statements. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates in the Preparation of Financial Statements	'
	Use of Estimates in the Preparation of Financial Statements—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s most significant recurring estimates are based on remaining proved oil and gas reserves. Estimates of proved reserves are key components of the Company’s depletion rate for oil and gas properties and its full cost ceiling test limitation. In addition, estimates are used in computing fair value of impaired assets, taxes, asset retirement obligations, fair value of derivative contracts and other items. Actual results could differ from these estimates.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents—The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Cash balances are maintained at a few financial institutions that are insured by the Federal Deposit Insurance Corporation although such balances at times are in excess of the insured amount; however, no losses have been recognized as a result of this circumstance. During 2011, the Company began utilizing a controlled disbursement cash account which is funded when outstanding checks and electronic payments are presented for payment and an overdraft is the normal book balance. The Company’s policy has been to fund these outstanding checks and electronic payments as they clear through the banking system with customer receipts and borrowings under its Borrowing Base Credit Facility (as defined below). The Company accounts for such book overdrafts by reporting them in accounts and revenue payable in its consolidated balance sheets and including the change in such amounts in cash flows from operating activities in its consolidated statements of cash flows. Outstanding checks and electronic payments included in accounts and revenue payable at December 31, 2012 and 2013, amounted to $6.6 million and $4.5 million, respectively.
Accounts Receivable	'
	Accounts Receivable—The Company conducts the majority of its operations in Kansas and Oklahoma and operates exclusively in the oil and gas industry. Receivables are generally unsecured; however, the Company has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements. Management periodically assesses the accounts receivable and establishes an allowance for estimated uncollectible amounts. Accounts estimated to be uncollectible are charged to operations in the period the reserve is established. The allowance for doubtful accounts was approximately $193,000 and $194,000 at December 31, 2012 and 2013, respectively.
Inventory	'
	Inventory—Inventory includes tubular goods and other lease and well equipment which the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties—The Company uses the full cost method of accounting for oil and gas properties. Under the full cost method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of its oil and gas properties are capitalized.
	Oil and gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved oil and gas reserves. Estimation of proved oil and gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates that are materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of oil and gas properties such will result in an amortization rate materially different from the amortization rate calculated upon recognition of gains or losses.
	Under the full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum less income tax effects (the “ceiling limitation”). The Company performs a quarterly ceiling test to evaluate whether the net book value of its full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion, and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ (deficit) equity in the period of occurrence and typically results in lower depreciation, depletion, and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The risk that the Company will be required to write down the carrying value of its oil and gas properties increases when oil and gas prices are depressed, even if low prices are temporary. This is partially mitigated by the use of an unweighted arithmetic first day of the month price for trailing average twelve-month market prices to determine the ceiling. In addition, a write-down may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly.
Unevaluated Properties	'
	Unevaluated Properties—The costs directly associated with unevaluated oil and gas properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs and cumulative drilling costs to date associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in the Company’s unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of numerous factors, including intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, assignment of proved reserves and economic viability of development if proved reserves are assigned. Any impairments of unevaluated properties are transferred to the amortization base.
Capitalized General and Administrative Expenses	'
	Capitalized General and Administrative Expenses—Under the full cost method of accounting, a portion of general and administrative expenses that are directly attributable to acquisition, exploration, and development activities are capitalized to the full cost pool. The capitalized costs include salaries, related fringe benefits, cost of consulting services and other costs directly associated with those activities. In addition to costs related to acquisition, exploration, and development activities, the Company has also capitalized certain software costs. The Company’s capitalized general and administrative costs including software costs were $1.1 million, $904,000 and $1.3 million for the years ended December 31, 2011, 2012 and 2013, respectively.
Capitalized Interest Costs	'
	Capitalized Interest Costs—The Company capitalizes interest based on the cost of major development projects. Capitalized interest was $51,000,  $11,000 and nil for the years ended December 31, 2011, 2012 and 2013, respectively.
Other Property and Equipment	'
	Other Property and Equipment—The cost of other property and equipment is depreciated over the estimated useful lives of the related assets. The cost of leasehold improvements is depreciated over the lesser of the length of the related leases or the estimated useful lives of the assets.
	Upon disposition or retirement of property and equipment, other than oil and gas properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is recognized in the statement of operations in the period of sale or disposition. Maintenance and repair costs are charged to operating expense as incurred.
Impairment	'
	Impairment—Long-lived assets such as property and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. If the carrying amount of such assets exceeds their undiscounted estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets.
Equity Investment	'
	Equity Investment—The Company elected to measure its investment in Constellation Energy Partners LLC (“CEP”) at fair value with changes in fair value included in the consolidated statements of operations. If the Company had not elected the fair value method, the investment would have previously qualified for the equity method of accounting, under which the Company’s proportionate share of the investee’s income would have been reported in the consolidated statements of operations.
Asset Retirement Obligations	'
	Asset Retirement Obligations—Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost and the corresponding liability should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its natural gas and oil wells. Asset retirement obligations associated with the retirement of a tangible long-lived asset are recognized as a liability in the period incurred or when it becomes determinable that there is a legal or contractual obligation to dismantle or dispose of the asset and reclaim or remediate any related property at the end of its useful life, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. The Company has not recorded an asset retirement obligation relating to its gathering system because it does not have any legal or constructive obligations relative to asset retirements of the gathering system.
Derivative Instruments	'
	Derivative Instruments—The Company utilizes derivative instruments in conjunction with marketing and trading activities to manage price risk attributable to its forecasted sales of oil and gas production.
	The Company does not designate its oil and natural gas derivative contracts as hedges under ASC 815 Derivatives and Hedging  although it believes that such contracts are effective hedges of its commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on the Company’s consolidated balance sheets under the caption “Derivative financial instruments.” Changes in the fair value of these derivative financial instruments are recorded in earnings.  The Company recognizes all unrealized and realized gains and losses related to these contracts on its consolidated statements of operations under the captions “Realized gain (loss) from derivative financial instruments” and “Unrealized gain (loss) from derivative financial instruments” both which are components of “Other income (expense)”.
	The Company has exposure to credit risk to the extent a counterparty to a derivative instrument is unable to meet its settlement commitment. It actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.
Legal	'
	Legal—The Company is subject to certain legal proceedings, claims and liabilities which arise in the ordinary course of its business. It accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These estimates are adjusted as additional information becomes available or circumstances change.
Revenue Recognition	'
	Revenue Recognition—Revenue from the Company’s oil and gas operations is derived from the sale of produced oil and natural gas. The Company uses the sales method of accounting for the recognition of oil and gas revenue. Because there is a ready market for oil and gas, the Company sells its oil and gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title and risk of loss is transferred based on the Company’s net revenue interests. Gathering revenue is recognized at the time the gas is gathered or transported through the system and delivered to a third party as evidenced by a contract.
Environmental Costs	'
	Environmental Costs—Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. The Company has no environmental costs accrued for the periods presented.
Stock-Based Compensation	'
	Stock-Based Compensation—The Company grants various types of stock-based awards including stock options, restricted stock and restricted stock units to its employees and non-employee directors. The Company accounts for stock-based compensation in accordance with FASB ASC 718 Compensation – Stock Compensation where the awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the consolidated statement of operations over the applicable requisite service periods. The fair value of stock option awards is determined using a Black-Scholes pricing model where volatility is derived from a peer group of companies.
Deferred Compensation Plan	'
	Deferred compensation plan—The Company’s deferred compensation plan permits selected employees and members of its board of directors to defer part or all of their eligible compensation. The Company accounts for this deferred compensation in accordance with FASB ASC 710 Compensation – General. The Company issues common stock into a rabbi trust created to hold the assets associated with the plan. A participant’s deferred compensation is credited with earnings, gains and losses based on the Company’s common stock, the only investment option currently available under the plan. The Company may also make discretionary employer credits in an amount it determines each plan year. Distributions to participants will be made in shares of the Company’s common stock. Company shares held in the rabbi trust are recorded as treasury stock in the consolidated balance sheets. Since the deferred compensation arrangement currently does not permit diversification and only allows for settlement by delivery of Company common stock, the obligation is recorded as a component of paid-in-capital and changes in the fair value of the obligation are not recognized.
Income Taxes	'
	Income Taxes—The Company records its income taxes using an asset and liability approach in accordance with the provisions of the FASB ASC 740 Income Taxes. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences (primarily property and equipment and the net operating loss carry forward) between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under FASB ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2012 and 2013,  a full valuation allowance was recorded against the Company’s net deferred tax assets.
	The Company regularly analyzes tax positions taken or expected to be taken in a tax return based on the threshold condition prescribed under FASB ASC 740. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. The Company accrues interest and penalties related to uncertain tax positions as income tax expense.
Net Income (Loss) per Common Share	'
	Net Income (Loss) per Common Share—Basic earnings (loss) per share is calculated by dividing net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the period. The Company also includes contingently issuable shares in basic earnings (loss) per share when there is no circumstance under which those shares would not be issued. These include vested shares under the Company’s deferred compensation plan and vested deferred restricted stock units as all necessary conditions have been satisfied for the issuance of those shares other than the passage of time. Diluted earnings (loss) per share assumes the conversion of all potentially dilutive securities (warrants, stock options and restricted stock awards) and is calculated by dividing net income (loss) by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities under the treasury stock method.
Concentrations of Market Risk	'
	Concentrations of Market Risk—The Company’s future results will be affected by the market price of oil and gas. The availability of a ready market for oil and gas will depend on numerous factors beyond the Company’s control, including weather, production of oil and gas, imports, marketing, competitive fuels, proximity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil and gas, the regulatory environment, and other regional and political events, none of which can be predicted with certainty.
Concentrations of Credit Risk	'
	Concentrations of Credit Risk—Financial instruments, which subject the Company to concentrations of credit risk, consist primarily of cash and accounts receivable. Risk with respect to receivables at December 31, 2012 and 2013, arise substantially from the sales of oil and gas. The following table discloses the percentage of consolidated revenues from our major customers:
		Year Ended December 31,
		2012		2013
	British Petroleum Energy Company	22	%	56	%
	ONEOK Energy and Marketing and Trading Company	34	%	11	%
	Sunoco	9	%	11	%
Fair Value	'
	Fair Value—The Company applies the provisions of FASB ASC 820 Fair Value Measurements and Disclosures. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.
	FASB ASC 820 also establishes a hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:
	•Level 1—Quoted prices available in active markets for identical assets or liabilities at the reporting date.
	•Level 2—Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable at the reporting date. Level 2 consists primarily of non-exchange traded commodity derivatives.
	•Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources.
	The Company classifies assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Transfers of assets and liabilities between Level 1 and Level 2 are recognized at the end of a reporting period. The Company prioritizes the use of the highest level inputs available in determining fair value.
Recent Accounting Pronouncements	'
	Recent Accounting Pronouncements
	In December 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities requiring entities to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on the financial position of an entity. The disclosure affects all entities with financial instruments and derivatives that are either offset on the balance sheet or subject to a master netting arrangement, irrespective of whether they are offset on the balance sheet. This information will enable users of an entity’s financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. The guidance is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods. Other than the additional disclosure requirements, which are presented in Note 6—Derivative Financial Instruments, the Company’s adoption of this guidance did not have an impact on its financial statements.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]	'
Summary of Percentage of Consolidated Revenue from Major Customers	'
		Year Ended December 31,
		2012		2013
	British Petroleum Energy Company	22	%	56	%
	ONEOK Energy and Marketing and Trading Company	34	%	11	%
	Sunoco	9	%	11	%

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
Acquisitions and Divestitures [Abstract]	'
Schedule of Fair Value of Consideration Given and Purchase Price Allocation of Assets and Liabilities Assumed	'
	Consideration given (in thousands)
	Cash	$	3,440
	Common stock		6,548
	Total consideration given	$	9,988
	Amounts recognized for fair value of assets acquired and liabilities assumed
	Proved oil and natural gas properties	$	7,081
	Unproved oil and natural gas properties		3,253
	Crude oil inventory		177
	Accounts receivable		167
	Asset retirement obligations		-538
	Accounts payable		-152
	Total fair value of oil and gas properties acquired	$	9,988

Other_Balance_Sheet_Items_Tabl

Other Balance Sheet Items (Tables)	12 Months Ended
	Dec. 31, 2013
Other Balance Sheet Items [Abstract]	'
Other Balance Sheet Items	'
		December 31,
		2012		2013
		(in thousands)
	Other current assets
	Prepaid fees and deposits	$	1,036	$	820
	Escrowed funds from Appalachian Basin sale (1)		564		—
	Escrowed funds from KPC sale (2)		500		—
	Total	$	2,100	$	820
	Other noncurrent assets, net
	Deferred financing costs	$	1,668	$	1,547
	Noncurrent deposits and other		512		491
	Total	$	2,180	$	2,038
	Accrued expenses and other
	Interest	$	56	$	39
	Employee-related costs and benefits		1,790		1,062
	Non-income related taxes		88		72
	Escrowed funds due to third parties (3)		400		—
	KPC site cleanup costs (4)		313		—
	Fees for services		1,327		1,127
	Asset retirement obligations		—		129
	Current income taxes		—		80
	Other		954		1,546
	Total	$	4,928	$	4,055
	Other noncurrent liabilities
	Lease termination costs	$	255	$	75
	Other		61		—
	Total	$	316	$	75
	____________
	(1)Escrowed funds relate to the proceeds from the Appalachian Basin sale. The escrowed funds are restricted to cover indemnities and title defects related to the sale. In 2012, $5.7 million in escrowed funds were released after $219,000 in net claims were paid. The remaining $564,000 was released to MHR in January 2013.
	(2)Escrowed funds relate to the proceeds from the KPC sale and were released to the Company in January 2013 upon acceptable cleanup of a site previously owned by KPC.
	(3)The balance at December 31, 2012, represented escrowed funds from the Appalachian Basin sale that were released to MHR in January 2013.
	(4)Represent accrued costs for cleanup of a site previously owned by KPC as discussed above.

Property_Tables

Property (Tables)	12 Months Ended
	Dec. 31, 2013
Property [Abstract]	'
Schedule of Oil and Gas Properties and Other Property and Equipment	'
		December 31,
		2012		2013
		(in thousands)
	Oil and gas properties under the full cost method of accounting
	Properties being amortized	$	353,093	$	405,895
	Properties not being amortized		31		4,862
	Total oil and gas properties, at cost		353,124		410,757
	Less accumulated depletion, depreciation and amortization		-245,593		-268,846
	Oil and gas properties, net		107,531		141,911
	Other property and equipment at cost	$	30,247	$	30,019
	Less accumulated depreciation		-16,003		-15,839
	Other property and equipment, net	$	14,244	$	14,180
Schedule of Estimated Useful Lives of Other Property and Equipment	'
	Buildings	25 years
	Machinery and equipment	10 years
	Software and computer equipment	3 years
	Furniture and fixtures	10 years
	Vehicles	5 years

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Financial Instruments [Abstract]	'
Derivative Financial Instruments on Consolidated Balance Sheets	'
				December 31,
				2012			2013
	Derivative Financial Instruments		Balance Sheet Location	(in thousands)
	Commodity contracts		Current derivative financial instrument asset	$	1,771		$	54
	Commodity contracts		Long-term derivative financial instrument asset		615			652
	Commodity contracts		Current derivative financial instrument liability		-4,449			-1,937
	Commodity contracts		Long-term derivative financial instrument liability		-2,638			-1,796
				$	-4,701		$	-3,027
Gains and Losses Associated with Derivative Financial Instruments	'
		Year Ended December 31,
		2011			2012			2013
		(in thousands)
	Realized gains (losses)(1)	$	33,692		$	73,162		$	-2,271
	Unrealized gains (losses)		1,737			-66,708			1,672
	Total gain (loss) from derivative financial instruments	$	35,429		$	6,454		$	-599
	___________
	(1)2012 includes $30.2 million received from exiting above market natural gas swap contracts originally scheduled for delivery in 2013.
Estimated Volumes, Fixed Prices and Fair Values Attributable to All of Company Oil and Gas Derivative Contracts	'
	The following table summarizes the estimated volumes, fixed prices and fair values attributable to all of the Company’s oil and gas derivative contracts at December 31, 2013.
			Year Ending December 31,
			2014			2015			2016			Total
			($ in thousands, except per unit data)
	Natural Gas Swaps
	Contract volumes (MMBtu)			10,327,572			8,983,560			7,814,028			27,125,160
	Weighted-average fixed price per MMBtu		$	4.01		$	4.01		$	4.01		$	4.01
	Fair value, net		$	-1,800		$	-1,076		$	-719		$	-3,595
	Crude Oil Swaps
	Contract volumes (Bbl)			116,076			71,568			65,568			253,212
	Weighted-average fixed price per Bbl		$	95.19		$	92.73		$	90.33		$	93.23
	Fair value, net		$	-53		$	281		$	340		$	568
	Total fair value, net		$	-1,853		$	-795		$	-379		$	-3,027
	The following table summarizes the estimated volumes, fixed prices and fair values attributable to all of the Company’s oil and gas derivative contracts at December 31, 2012:
		Year Ending December 31,
		2013			2014			2015			2016			Total
		($ in thousands, except per unit data)
	Natural Gas Swaps
	Contract volumes (MMBtu)		3,747,285			4,324,032			3,755,184			3,765,840			15,592,341
	Weighted-average fixed price per MMBtu	$	3.95		$	3.95		$	3.95		$	3.96		$	3.95
	Fair value, net	$	1,270		$	-320		$	-908		$	-1,410		$	-1,368
	Natural Gas Basis Swaps
	Contract volumes (MMBtu)		9,000,003			—			—			—			9,000,003
	Weighted-average fixed price per MMBtu	$	-0.71		$	—		$	—		$	—		$	-0.71
	Fair value, net	$	-4,448		$	—		$	—		$	—		$	-4,448
	Crude Oil Swaps
	Contract volumes (Bbl)		65,892			61,680			58,164			53,892			239,628
	Weighted-average fixed price per Bbl	$	101.70		$	97.00		$	93.40		$	91.10		$	96.09
	Fair value, net	$	546		$	276		$	168		$	125		$	1,115
	Total fair value, net	$	-2,632		$	-44		$	-740		$	-1,285		$	-4,701
Reconciliation Of Gross Amounts To Net Amounts	'
		December 31,
		2012			2013
		(in thousands)
	Derivative Assets
	Gross amounts of recognized assets	$	2,386		$	706
	Gross amounts offset in the balance sheet		—			—
	Net amounts of assets presented in the balance sheet		2,386			706
	Gross amounts not offset in the balance sheet		-2,386			-706
	Net amount	$	—		$	—
	Derivative Liabilities
	Gross amounts of recognized liabilities	$	7,087		$	3,733
	Gross amounts offset in the balance sheet		—			—
	Net amounts of liabilities presented in the balance sheet		7,087			3,733
	Gross amounts not offset in the balance sheet		-2,386			-706
	Net amount	$	4,701		$	3,027

Financial_Instruments_Tables

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Financial Instruments [Abstract]	'
Assets and Liabilities Measured at Fair Value on Recurring Basis	'
								Total Net Fair
		Level 1		Level 2		Level 3		Value
		(in thousands)
	At December 31, 2012
	Equity investment	$	6,984	$	836	$	—	$	7,820
	Derivative financial instruments—assets		—		2,386		—		2,386
	Derivative financial instruments—liabilities		—		-7,087		—		-7,087
	Total	$	6,984	$	-3,865	$	—	$	3,119
	At December 31, 2013
	Equity investment	$	14,205	$	383	$	—	$	14,588
	Derivative financial instruments—assets		—		706		—		706
	Derivative financial instruments—liabilities		—		-3,733		—		-3,733
	Total	$	14,205	$	-2,644	$	—	$	11,561

Equity_Investment_Tables

Equity Investment (Tables)	12 Months Ended
	Dec. 31, 2013
Equity Investment [Abstract]	'
Effect of Mark to Market Gains (Losses) on Equity Investment	'
		Year ended December 31,
		2011			2012		2013
		(in thousands)
	Mark to market gains (losses) on equity investment	$	-4,607		$	-5,174	$	6,768
Summarized Condensed Financial Information of CEP	'
		Year ended December 31,
		2011			2012		2013
		(in thousands)
	Gross revenues	$	105,217		$	59,335	$	46,381
	Gross profit (loss)(1)		29,453			-80,964		-25,589
	Net income (loss) from continuing operations (2)		—			-9,462		-25,857
	Net income (loss)		19,586			-86,543		-28,543
	____________
		-1		Equals revenues less operating expenses
		-2		Net income from continuing operations is not available for 2011

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations [Abstract]	'
Schedule of Changes in Asset Retirement Obligations	'
		Year Ended December 31,
		2012		2013
		(in thousands)
	Asset retirement obligations at beginning of period (1)	$	10,087	$	10,868
	Liabilities incurred		160		533
	Liabilities settled		-111		-88
	Acquisitions		—		538
	Accretion		743		811
	Revision of estimates		-11		566
	Asset retirement obligations at end of period	$	10,868	$	13,228
	Current portion of asset retirement obligations	$	—	$	129
	Noncurrent portion of asset retirement obligations at end of period	$	10,868	$	13,099
	____________
	(1)Amounts in the table do not include the asset retirement obligations of KPC which was divested by the Company during 2012.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-Term Debt [Abstract]	'
Summary of Long-Term Debt	'
		December 31,
		2012		2013
		(in thousands)
	Borrowing Base Facility	$	57,500	$	92,000
	Less current maturities		—		—
	Total long-term debt	$	57,500	$	92,000

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Taxes [Abstract]	'
Reconciliation of Federal Income Taxes at Federal Rates to Actual Provision for Income Taxes	'
		Year Ended December 31,
		2011		2012		2013
		(in thousands)
	Income tax expense (benefit) at statutory rate	$	7,011	$	-16,650	$	-3,100
	State income tax expense (benefit), net of federal		647		958		19
	Effect of the Recombination		—		—		—
	2011 IRS Settlement		—		—		30
	Other		2,942		1,650		496
	IRC Section 382 limitation		-2,135		30,491		2,575
	Change in valuation allowance		-8,465		-16,449		160
	Total tax expense (benefit)	$	—	$	—	$	180
Summary of Deferred Tax Assets and Liabilities	'
		Year Ended December 31,
		2012		2013
		(in thousands)
	Current deferred income tax assets
	Unrealized loss for commodity derivative recorded for book, not for tax	$	1,658	$	722
	Accrued liabilities		1,047		1,038
	Allowance for bad debts		72		72
	Other		630		277
	Total current deferred income tax assets		3,407		2,109
	Noncurrent deferred income tax assets
	Unrealized loss for commodity derivative recorded for book, not for tax		983		669
	Partnership basis differences		6,037		6,287
	Property and equipment		45,733		37,849
	Asset retirement obligations		1,871		2,173
	Net operating loss carryforwards		18,459		14,943
	Other carryforwards		1,516		2,264
	Total noncurrent deferred income tax assets		74,599		64,185
	Total deferred income tax assets		78,006		66,294
	Current deferred income tax liabilities
	Unrealized gain for commodity derivative recorded for book, not for tax		-11,905		-20
	Other		—		—
	Total current deferred income tax liabilities		-11,905		-20
	Noncurrent deferred income tax liabilities
	Unrealized gain for commodity derivative recorded for book, not for tax		-407		-420
	Total noncurrent deferred income tax liabilities		-407		-420
	Total deferred income tax liabilities		-12,312		-440
	Net deferred income tax assets		65,694		65,854
	Valuation allowance		-65,694		-65,854
	Total deferred tax asset (liability)	$	—	$	—

Redeemable_Preferred_Stock_and1

Redeemable Preferred Stock and Warrants (Tables)	12 Months Ended
	Dec. 31, 2013
Redeemable Preferred Stock and Warrants [Abstract]	'
Changes in Series A Preferred Stock and Associated Warrants	'
		Carrying Value		Carrying Value		Number of
		of Series A		of Series A		Outstanding		Liquidation Value		Number of	Weighted Average
		Preferred Stock in		Preferred Stock		Series A		of Series A		Outstanding	Exercise Price of
		Temporary Equity		in Liabilities		Preferred Shares		Preferred Stock		Warrants	Warrants
		(in thousands except share, warrant and per unit data)
	31-Dec-10	$	50,622	$	—	6,000		$	61,980	19,584,205	$	3.16
	Accrued dividends		4,534		—	—			7,779	1,982,040		3.92
	Accretion		1,580		—	—			—	—		—
	31-Dec-11		56,736		—	6,000			69,759	21,566,245		3.23
	Issuance		8,428		—	1,250			12,500	7,654,387		1.63
	Accrued dividends		5,750		—	—			9,083	5,115,782		1.78
	Accretion		2,238		—	—			—	—		—
	31-Dec-12		73,152		—	7,250			91,342	34,336,414		2.66
	Accrued dividends		7,479		—	—			11,047	8,066,270		1.42
	Accrued dividends recorded as interest		—		—	—			417	—		—
	Warrant Exchange		-60,086		64,443	—			—	-22,241,333		3.23
	Accretion		3,283		80	—			—	—		—
	31-Dec-13	$	23,828	$	64,523	7,250		$	102,806	20,161,351	$	1.54
Changes to Additional Paid in Capital as a Result of Warrants Issued	'
		Year Ended December 31,
		2011		2012		2013
		(in thousands)
	Warrants issued in conjunction with issuance of Series A Preferred Stock	$	—	$	4,071	$	—
	Warrants issued in conjunction with paid-in-kind dividends		3,245		3,334		3,984
	Total change in APIC due to warrants issued	$	3,245	$	7,405	$	3,984

Equity_And_Earnings_Per_Share_

Equity And Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Equity And Earnings Per Share [Line Items]	'
Summary of Changes in the Non-Vested Restricted Shares	'
		Number of Non-Vested		Weighted Average Grant
		Restricted Shares		Date Fair Value
	Non-vested restricted shares at December 31, 2010	375,358		$	4.83
	Granted	487,500			2.90
	Vested	-80,554			5.91
	Forfeited	-203,094			5.08
	Non-vested restricted shares at December 31, 2011	579,210			3.33
	Granted	1,295,112			2.01
	Vested	-275,900			3.23
	Forfeited	-118,856			3.76
	Non-vested restricted shares at December 31, 2012	1,479,566			2.16
	Granted	641,902			1.75
	Vested	-452,529			2.79
	Cancelled/Forfeited (1)	-1,053,673			1.79
	Non-vested restricted shares at December 31, 2013	615,266		$	1.89
	____________
	(1)  787,414 shares were cancelled with an associated accelerated stock compensation expense of approximately $500,000.
Summary of Changes in Stock Options Outstanding	'
				Weighted Average			Weighted Average
		Stock options		Exercise Price per			Grant Date Fair
				Option			Value per Option
	Options outstanding at December 31, 2010	567,050		$	4.17
	Granted	799,400			3.63		$	2.15
	Exercised (1)	-20,000			3.29
	Forfeited or expired	-289,600			4.07
	Options outstanding at December 31, 2011	1,056,850			3.59
	Granted	1,303,653			1.80			1.07
	Forfeited or expired	-190,220			4.30
	Options outstanding at December 31, 2012	2,170,283			2.45
	Granted	584,949			1.77			0.89
	Forfeited or expired	-448,813			1.92
	Options outstanding at December 31, 2013	2,306,419			2.38
	Exercisable
	Options exercisable at December 31, 2011	310,922		$	5.57
	Options exercisable at December 31, 2012	467,189			4.10
	Options exercisable at December 31, 2013	989,037			3.03
	____________
	(1)The Company received $66,000 upon exercise of these options which had a total intrinsic value of $34,000 at the exercise dates.
Weighted-Average Assumptions to Estimate the Fair Value of Stock Options Granted	'
		2011				2012				2013
	Expected option life-years		6-May				5				4
	Volatility		74.4 - 77.0	%			74.3 - 76.1	%			64.0 - 82.7	%
	Risk-free interest rate		0.9 - 2.0	%			0.9 - 1.3	%			0.6 - 1.4	%
	Dividend yield		—				—				—
	Fair value per share	$	1.43 - 4.53			$	0.87 - 1.88			$	0.82 - 1.03
Total Share-Based Compensation Covering Stock Awards and Options	'
		Total Share
		Based
		Compensation
		Expense
		(in thousands)
	Year Ended December 31, 2011	$	1,258
	Year Ended December 31, 2012		2,224
	Year Ended December 31, 2013		3,177
Reconciliation of Numerator and Denominator Used in Basic and Diluted Per Share Calculations	'
		Year Ended December 31,
		2011		2012		2013
	Denominator for basic earnings per share (1)	8,785,551		13,595,843		25,068,574
	Effect of potentially dilutive securities
	Unvested share-based awards	127,600		—		—
	Warrants	6,089,339		—		—
	Stock options	47,230		—		—
	Denominator for diluted earnings per share	15,049,720		13,595,843		25,068,574
	Securities excluded from earnings per share calculation
	Unvested share-based awards	14,998		149,988		—
	Antidilutive stock options	1,056,850		2,170,283		2,306,419
	Warrants	1,830,464		33,086,615		17,929,512
	____________
	(1)Includes vested common shares in the Company’s deferred compensation plan and vested deferred restricted stock units, both of which will deliver shares to participants at a later date. Although shares have not been delivered on these awards, all conditions for issuance and delivery have been met. Pursuant to FASB ASC 260-10-45-13, such shares are to be included in the denominator in calculating basic earnings per share.
White Deer [Member]	'
Equity And Earnings Per Share [Line Items]	'
Schedule of Common Stock Issuance	'
		Feb-12			Aug-12			Dec-12
	Gross proceeds (in thousands)	$	7,500		$	6,000		$	6,500
	Common shares sold		2,180,233			3,076,923			4,577,464
Universal Shelf Registration Statement [Member]	'
Equity And Earnings Per Share [Line Items]	'
Schedule of Common Stock Issuance	'
		Year Ended December 31,
		2012			2013
	Gross proceeds (in thousands)	$	724		$	4,076
	Common shares sold		446,098			2,592,313

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies [Abstract]	'
Future Minimum Rental Payments Under All Non-Cancelable Operating Leases	'
	Year ending December 31,	(in thousands)
	2014	$	3,558
	2015		2,468
	2016		847
	2017		373
	2018		10
	Thereafter		—
	Total minimum lease obligations	$	7,256

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2013
Discontinued Operations [Abstract]	'
Results of Discontinued Operations	'
		Year Ended December 31,
		2011		2012
		(in thousands)
	Interstate pipeline revenue	$	11,183	$	8,934
	Pipeline expense		-5,219		-2,825
	Depreciation and amortization		-3,574		-2,537
	Gain (loss) on disposal of assets (1)		3		-5,437
	General and administrative expenses		-1,194		-945
	Interest expense		-556		-45
	Income from discontinued operations before income taxes		643		-2,855
	Income taxes		—		—
	Total income (loss) from discontinued operations	$	643	$	-2,855
	____________
	(1)Includes a loss of $5.4 million from the disposal of KPC.

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Summary of Supplemental Cash Flow Information	'
		Year Ended December 31,
		2011		2012		2013
		(in thousands)
	Cash paid for interest	$	8,623	$	7,292	$	2,780
	Cash paid for income taxes		—		—		100
	Non-cash investing activity
	Common stock issued for purchase of equity investment		4,100		—		—
	Common stock issued for purchase of oil and gas properties		—		—		6,728
	Common stock issued to fund 401K and deferred compensation plans		—		—		931
	Common stock issued to repurchase and retire outstanding warrants		—		—		1,528
	Warrants issued for purchase of equity investment		518		—		—
	Equity securities received on the sale of oil and gas properties		5,875		—		—
	Property additions financed through accounts payable and accrued liabilities		830		239		1,010
	Additions to property and equipment by recognizing asset retirement obligations		4,067		159		1,099
	Non-cash financing activity
	Reduction of debt through conveyance of financial securities received from sale of oil and gas properties		5,729		—		—
	Reduction of debt through issuance of common stock		843		—		—
	Issuance of preferred stock and warrants in lieu of cash dividends		7,779		9,083		11,464
	Accretion of discount on redeemable preferred stock reflected in interest expense		—		—		80
	Accretion of discount on redeemable preferred stock		1,580		2,238		3,283

Profit_Sharing_Plan_And_Deferr

Profit Sharing Plan And Deferred Compensation Plan (Tables)	12 Months Ended
	Dec. 31, 2013
Profit Sharing And Deferred Compensation Plan [Abstract]	'
Schedule of Profit Sharing Plan	'
		Year Ended December 31,
		2011			2012		2013
		(in thousands)
	401(k) profit sharing plan cost	$	492		$	235	$	662
Schedule Of Deferred Compensation	'
			Year Ended
			31-Dec-13
			($ in thousands)
	Shares of common stock contributed			324,522
	Fair value of common stock contributed		$	473

Supplemental_Financial_Informa1

Supplemental Financial Information-Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Financial Information-Quarterly Financial Data [Abstract]	'
Schedule of Quarterly Financial Information	'
		Quarters Ended
		March 31,		June 30,		September 30,		December 31,
		(in thousands, except per share data)
	2012
	Total revenues	$	14,321	$	11,124	$	13,697	$	15,853
	Operating income (loss) (1)		-7,501		-10,352		-11,409		-6,649
	Net income (loss)		7,347		-18,508		-25,174		-11,237
	Net income (loss) per common share
	Basic	$	0.43	$	-1.71	$	-1.94	$	-0.89
	Diluted	$	0.37	$	-1.71	$	-1.94	$	-0.89
		Quarters Ended
		March 31,		June 30,		September 30,		December 31,
		(in thousands, except per share data)
	2013
	Total revenues	$	16,053	$	19,594	$	18,614	$	18,039
	Operating income (loss) (1)		-3,727		-2,019		-1,679		-3,873
	Net income (loss)		-7,894		6,880		-645		-7,377
	Net income (loss) per common share
	Basic	$	-0.5	$	0.13	$	-0.18	$	-0.38
	Diluted	$	-0.5	$	0.13	$	-0.18	$	-0.38
	____________
	(1)Total revenue less total costs and expenses.

Supplemental_Information_on_Oi1

Supplemental Information on Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Aggregate Capitalized Costs Related to Oil and Gas Producing Activities	'
		2012			2013
		(in thousands)
	Oil and gas properties and related leasehold costs
	Proved	$	353,093		$	405,895
	Unproved		31			4,862
			353,124			410,757
	Accumulated depreciation, depletion and amortization		-245,593			-268,846
	Net capitalized costs	$	107,531		$	141,911
Costs Incurred for Oil and Gas Property Acquisition, Exploration and Development Activities	'
		Consolidated Entities							CEP (1)
		2011			2012		2013		2011		2012		2013
		(in thousands)
	Proved property acquisition costs (2)	$	223		$	151	$	8,023	$	-74	$	20	$	4,262
	Unproved property acquisition costs		630			52		8,567		167		47		45
	Exploration costs		—			—		—		—		—		—
	Development Costs		23,825			12,506		40,004		2,895		4,064		3,343
		$	24,678		$	12,709	$	56,594	$	2,988	$	4,131	$	7,650
	____________
	(1)Based on the Company’s pro-rata interest in CEP (disclosed above) assuming that the Company’s investment was made at the beginning of the period.
	(2)The amount is negative for CEP in 2011 as it represents a post-closing receipt from an acquisition made by CEP in December 2010.
Changes in Proved Developed and Undeveloped Reserves	'
		Gas - Mcf		Oil - Bbls
	Proved reserves
	Balance, December 31, 2010	130,462,031		744,266
	Purchase of reserves in place	—		—
	Extensions, discoveries, and other additions	1,752,746		54,761
	Sale of reserves	-754,479		—
	Revisions of previous estimates	5,068,946		352,981
	Production	-18,309,056		-78,087
	Balance, December 31, 2011	118,220,188		1,073,921
	Purchase of reserves in place	—		—
	Extensions, discoveries, and other additions	1,867,365		617,854
	Sale of reserves	—		—
	Revisions of previous estimates	-34,037,402		1,095,656
	Production	-16,388,878		-95,863
	Balance, December 31, 2012	69,661,273		2,691,568
	Purchase of reserves in place	98,822		554,892
	Extensions, discoveries, and other additions	1,122,511		1,911,959
	Sale of reserves	—		—
	Revisions of previous estimates	30,246,006		-585,342
	Production	-14,521,385		-192,474
	Balance, December 31, 2013	86,607,227		4,380,603
	Proved developed reserves
	Balance, December 31, 2011	117,406,577		1,040,309
	Balance, December 31, 2012	69,661,273		1,804,057
	Balance, December 31, 2013	85,006,592		2,705,664
Best Estimate of Required Data for Standardized Measure of Discounted Future Net Cash Flows	'
		Consolidated Entities							CEP (1)
		2011			2012		2013		2011		2012		2013
		(in thousands)
	Future cash inflows	$	592,796		$	438,356	$	720,924	$	241,173	$	95,619	$	107,103
	Future production costs		312,410			218,707		315,079		132,081		51,462		48,418
	Future development costs		10,524			31,051		49,590		25,705		2,948		8,668
	Future income tax expense		—			—		30,149		—		—		—
	Future net cash flows		269,862			188,598		326,106		83,387		41,209		50,017
	10% annual discount for estimated timing of cash flows		94,342			86,516		156,977		40,964		17,446		19,406
	Standardized measure of discounted future net cash flows related to proved reserves	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
	Standardized measure from continuing operations	$	175,520		$	102,082	$	169,129	$	42,423	$	16,021	$	30,611
	Standardized measure from discontinued operations		—			—		—		—		7,742		—
	Standardized measure of discounted future net cash flows related to proved gas reserves	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
	____________
	(1)Represents the Company’s pro-rata share of its investment in CEP.
Discounted Future Cash Flow Estimates do not Include the Effects of Derivative Instruments	'
		2011			2012		2013
	Crude oil price per Bbl	$	96.19		$	95.05	$	96.94
	Natural gas price per MMBtu	$	4.12		$	2.76	$	3.67
Principal Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proven Oil and Gas Properties	'
		Consolidated Entities							CEP (1)
		2011			2012		2013		2011		2012		2013
		(in thousands)
	Present value, beginning of period	$	159,261		$	175,520	$	102,082	$	34,765	$	42,423	$	23,763
	Net changes in prices and production costs		11,876			18,071		37,826		38		-5,095		10,741
	Decrease in pro rata ownership		—			—		—		—		—		-4,664
	Net changes in future development costs		-1,154			-18,008		-30,462		—		—		—
	Previously estimated development costs incurred		18,192			12,743		40,196		1,892		4,987		1,196
	Sales of oil and gas produced, net		-32,751			-10,338		-29,604		-7,810		-10,520		-4,525
	Extensions and discoveries		3,045			7,724		23,514		2,157		3,336		6,069
	Purchases of reserves in-place		—			—		6,401		—		—		—
	Sales of reserves in-place		-1,104			—		—		—		-391		-489
	Revisions of previous quantity estimates		10,513			-38,064		49,926		11,243		-22,034		4,570
	Net change in income taxes		12,037			—		-7,769		—		—		—
	Accretion of discount		16,448			16,730		8,975		3,477		4,258		1,910
	Timing differences and other (2)		-20,843			-62,296		-31,956		-3,339		6,799		-7,960
	Present value, end of period	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
	Standardized measure from continuing operations	$	175,520		$	102,082	$	169,129	$	42,423	$	16,021	$	30,611
	Standardized measure from discontinued operations		—			—		—		—		7,742		—
	Standardized measure of discounted future net cash flows related to proved gas reserves	$	175,520		$	102,082	$	169,129	$	42,423	$	23,763	$	30,611
	____________
	(1)Represents the Company’s pro-rata share of its investment in CEP assuming that the Company’s investment was made at the beginning of each period presented.
	(2)The change in timing differences and other are related to revisions in the Company’s estimated time of production and development and the impact of changes in the relative proportion of oil versus natural gas in the Company’s total reserves.
CEP [Member]	'
Aggregate Capitalized Costs Related to Oil and Gas Producing Activities	'
		2012			2013
		(in thousands)
	Oil and gas properties and related equipment (successful efforts method)
	Proved	$	156,851		$	135,642
	Unproved		366			338
	Materials, supplies and land		402			385
			157,619			136,365
	Accumulated depreciation, depletion and amortization		-125,787			-105,481
	Net capitalized costs	$	31,832		$	30,884
Pro-Rata Results of Oil and Gas Producing Activities of Investment in CEP	'
		2011			2012		2013
		(in thousands)
	Revenues	$	27,778		$	12,330	$	9,388
	Lease operating expense		7,379			5,144		4,017
	Cost of sales and production taxes		1,343			780		864
	Exploration costs		35			—		—
	Impairment of oil and gas properties		775			29		502
	Depreciation, depletion and amortization		5,845			3,109		4,041
Changes in Proved Developed and Undeveloped Reserves	'
		Mcfe
	Proved reserves
	Balance, January 1, 2011	44,618,000
	Purchase of reserves in place	—
	Extensions, discoveries, and other additions	455,000
	Sale of reserves	—
	Revisions of previous estimates	11,216,000
	Production	-3,138,000
	Balance, December 31, 2011	53,151,000
	Purchase of reserves in place	—
	Extensions, discoveries, and other additions	543,000
	Sale of reserves	-68,000
	Revisions of previous estimates	-25,551,000
	Production	-3,435,000
	Balance, December 31, 2012	24,640,000
	Decrease in pro rata ownership	-4,835,000
	Purchase of reserves in place	1,523,000
	Extensions, discoveries, and other additions	1,028,000
	Sale of reserves	-10,519,000
	Revisions of previous estimates	9,527,000
	Production	-1,927,000
	Balance, December 31, 2013	19,437,000
	Proved developed reserves
	Balance, December 31, 2011	40,295,000
	Balance, December 31, 2012	23,850,000
	Balance, December 31, 2013	16,748,000

Business_Organization_Narrativ

Business Organization (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
	county
	segment
Business Organization [Abstract]	'
Number of segments	1
Number of counties	15

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Ownership of the outstanding voting stock of subsidiaries	50.00%	'	'
Accounts payable and revenue payable	$7,406,000	$9,373,000	'
Allowance for doubtful accounts	194,000	193,000	'
Capitalized general and administrative costs	1,300,000	904,000	1,100,000
Interest cost capitalized	0	11,000	51,000
Outstanding checks [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Accounts payable and revenue payable	$4,500,000	$6,600,000	'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Summary Of Percentage Of Consolidated Revenue From Major Customer) (Details) (Sales [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
British Petroleum Energy Company [Member]	'	'
Concentration Risk [Line Items]	'	'
Percentage of revenue	56.00%	22.00%
Oneok Energy Marketing And Trading Company [Member]	'	'
Concentration Risk [Line Items]	'	'
Percentage of revenue	11.00%	34.00%
Sunoco [Member]	'	'
Concentration Risk [Line Items]	'	'
Percentage of revenue	11.00%	9.00%

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures (Narrative) (Details) (USD $)

1 Months Ended

6 Months Ended

7 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2010

Jun. 30, 2011

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Jan. 31, 2014

Sep. 30, 2012

31-May-13

Nov. 30, 2013

Nov. 30, 2013

Nov. 30, 2013

Oil and gas properties [Member]

KPC Pipeline [Member]

Lincoln and Payne Counties in Oklahoma [Member]

Seminole County, Oklahoma [Member]

Pottawatomie, Cleveland and McClain Counties in Central Oklahoma [Member]

Pottawatomie, Cleveland and McClain Counties in Central Oklahoma [Member]

Subsequent Events [Member]

Oil and gas properties [Member]

Oil and gas properties [Member]

Oil and gas properties [Member]

acre

item

acre

acre

Business Acquisition And Divestiture [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Acres acquired

'

'

'

'

'

'

'

'

'

4,300

110

'

22,000

Aggregate purchase price

'

'

'

'

'

'

'

$1,800,000

'

$1,900,000

'

$9,988,000

'

Payments to acquire oil and gas property and equipment

'

'

'

52,283,000

16,759,000

29,338,000

'

900,000

'

1,700,000

750,000

'

'

Shares of common stock

'

'

'

'

'

'

'

725,806

'

126,602

'

'

4,516,129

Voting interest acquired

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

Number of producing wells acquired

'

'

'

'

'

'

'

'

'

'

3

'

'

Outstanding Class Member Interests

'

'

'

29,556,263

21,309,159

'

'

'

'

'

'

'

'

Disposal group purchase price, received

'

'

'

'

'

'

'

'

53,400,000

'

'

'

'

Sale of oil and gas properties

28,000,000

16,600,000

44,600,000

'

'

'

'

'

'

'

'

'

'

(Gain) loss on disposal of assets

'

'

'

'

'

12,500,000

13,700,000

'

'

'

'

'

'

Selling costs and adjustments

'

'

'

'

'

2,600,000

728,000

'

'

'

'

'

'

Reduction in oil and gas full cost

13,600,000

'

'

'

266,000

1,500,000

13,600,000

'

'

'

'

'

'

Escrow to cover potential claims

'

'

'

'

564,000

6,400,000

'

'

'

'

'

'

'

Escrowed funds released

'

'

'

'

5,700,000

'

'

'

'

'

'

'

'

Escrowed funds paid from second and third closing

'

'

'

'

219,000

'

'

'

'

'

'

'

'

Escrow deposit of first and second closing retained by company

'

'

'

'

1,300,000

'

'

'

'

'

'

'

'

Escrow deposit of first and second closing payment to lender

'

'

'

'

$4,400,000

'

'

'

'

'

'

'

'

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures (Schedule of Fair Value of Consideration Given and Purchase Price Allocation of Assets and Liabilities Assumed) (Details) (Pottawatomie, Cleveland and McClain Counties in Central Oklahoma [Member], USD $)	1 Months Ended
	Nov. 30, 2013
Pottawatomie, Cleveland and McClain Counties in Central Oklahoma [Member]	'
Business Acquisition [Line Items]	'
Cash	$3,440,000
Common stock	6,548,000
Total consideration given	9,988,000
Proved oil and natural gas properties	7,081,000
Unproved oil and natural gas properties	3,253,000
Crude oil inventory	177,000
Accounts receivable	167,000
Asset retirement obligations	-538,000
Accounts payable	-152,000
Total fair value of oil and gas properties acquired	$9,988,000

Other_Balance_Sheet_Items_Narr

Other Balance Sheet Items (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Balance Sheet Items [Abstract]	'	'	'
Escrowed funds released	'	$5,700,000	'
Net claims for escrow funds	'	219,000	'
Escrowed funds to be released	'	564,000	'
Amortization or write off expenses related to deferred financing costs	461,000	2,820,000	1,709,000
Write-off expense of unamortized debt issuance costs	'	$1,200,000	'

Other_Balance_Sheet_Items_Othe

Other Balance Sheet Items (Other Balance Sheet Items) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Other current assets	'	'		'
Prepaid fees and deposits	$820,000	$1,036,000		'
Escrow to cover potential claims	'	564,000		6,400,000
Total	820,000	2,100,000		'
Other noncurrent assets, net	'	'		'
Deferred financing costs	1,547,000	1,668,000		'
Noncurrent deposits and other	491,000	512,000		'
Total	2,038,000	2,180,000		'
Accrued expenses and other	'	'		'
Interest	39,000	56,000		'
Employee-related costs and benefits	1,062,000	1,790,000		'
Non-income related taxes	72,000	88,000		'
Escrowed funds due to third parties	'	400,000	[1]	'
KPC site cleanup costs	'	313,000	[2]	'
Fees for services	1,127,000	1,327,000		'
Asset retirement obligations	129,000	'		'
Current income taxes	80,000	'		'
Other	1,546,000	954,000		'
Total	4,055,000	4,928,000		'
Other noncurrent liabilities	'	'		'
Lease termination costs	75,000	255,000		'
Other	'	61,000		'
Total	75,000	316,000		'
Appalachian Basin sale [Member]	'	'		'
Other current assets	'	'		'
Escrow to cover potential claims	'	564,000	[3]	'
KPC sale [Member]	'	'		'
Other current assets	'	'		'
Escrow to cover potential claims	'	$500,000	[4]	'
[1]	The balance at December 31, 2012, represented escrowed funds from the Appalachian Basin sale that were released to MHR in January 2013.
[2]	Represent accrued costs for cleanup of a site previously owned by KPC as discussed above.
[3]	Escrowed funds relate to the proceeds from the Appalachian Basin sale. The escrowed funds are restricted to cover indemnities and title defects related to the sale. In 2012, $5.7 million in escrowed funds were released after $219,000 in net claims were paid. The remaining $564,000 was released to MHR in January 2013.
[4]	Escrowed funds relate to the proceeds from the KPC sale and were released to the Company in January 2013 upon acceptable cleanup of a site previously owned by KPC.

Property_Narrative_Details

Property (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]	'	'	'
Depreciation, depletion and amortization	$27,369,000	$27,669,000	$24,088,000
Increase amount in depletion depreciation and amortization	'	'	700,000
Oil and gas properties [Member]	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Depreciation, depletion and amortization	23,300,000	23,300,000	19,600,000
Other property plant and equipment [Member]	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Depreciation expense	$3,200,000	$3,600,000	$3,900,000

Property_Schedule_Of_Oil_And_G

Property (Schedule Of Oil And Gas Properties And Other Property And Equipment) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property [Abstract]	'	'
Properties being amortized (Proved)	$405,895	$353,093
Properties not being amortized (Unproved)	4,862	31
Total oil and gas properties, at cost	410,757	353,124
Accumulated depreciation, depletion and amortization	-268,846	-245,593
Oil and gas properties, net	141,911	107,531
Other property and equipment at cost	30,019	30,247
Less accumulated depreciation	-15,839	-16,003
Other property and equipment, net	$14,180	$14,244

Property_Schedule_Of_Estimated

Property (Schedule Of Estimated Useful Lives Of Other Property And Equipment (Details)	12 Months Ended
	Dec. 31, 2013
Buildings [Member]	'
Property, Plant and Equipment [Line Items]	'
Estimated useful lives of property and equipment	'25 years
Machinery and equipment [Member]	'
Property, Plant and Equipment [Line Items]	'
Estimated useful lives of property and equipment	'10 years
Software and computer equipment [Member]	'
Property, Plant and Equipment [Line Items]	'
Estimated useful lives of property and equipment	'3 years
Furniture and fixtures [Member]	'
Property, Plant and Equipment [Line Items]	'
Estimated useful lives of property and equipment	'10 years
Vehicles [Member]	'
Property, Plant and Equipment [Line Items]	'
Estimated useful lives of property and equipment	'5 years

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Derivative Financial Instruments on Consolidated Balance Sheets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'	'
Current derivative financial instrument asset	$54	$1,771
Long-term derivative financial instrument asset	652	615
Current derivative financial instrument liability	-1,937	-4,449
Long-term derivative financial instrument liability	-1,796	-2,638
Derivative financial instruments, fair value	-3,027	-4,701
Commodity Contracts [Member]	'	'
Derivative [Line Items]	'	'
Current derivative financial instrument asset	54	1,771
Long-term derivative financial instrument asset	652	615
Current derivative financial instrument liability	-1,937	-4,449
Long-term derivative financial instrument liability	($1,796)	($2,638)

Derivative_Financial_Instrumen3

Derivative Financial Instruments (Gains and Losses Associated with Derivative Financial Instruments) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Financial Instruments [Abstract]	'		'		'
Realized gains (losses)	($2,271,000)	[1]	$73,162,000	[1]	$33,692,000	[1]
Unrealized gains (losses)	1,672,000		-66,708,000		1,737,000
Total gain (loss) from derivative financial instruments	-599,000		6,454,000		35,429,000
Realized gain from early monetization of derivative instrument	'		$30,200,000		'
[1]	2012 includes $30.2 million received from exiting above market natural gas swap contracts originally scheduled for delivery in 2013.

Derivative_Financial_Instrumen4

Derivative Financial Instruments (Estimated Volumes, Fixed Prices and Fair Values Attributable to All of Company Oil and Gas Derivative Contracts) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
	MMBTU	MMBTU
Derivatives, Fair Value [Line Items]	'	'
Fair value, net	($3,027)	($4,701)
Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value, net	-3,027	-4,701
NYMEX Swap – Natural Gas 2013 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (MMbtu-gas)	'	3,747,285
Weighted-average fixed price per MMBtu	'	3.95
Fair value, net	'	1,270
NYMEX Swap – Natural Gas 2014 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (MMbtu-gas)	10,327,572	4,324,032
Weighted-average fixed price per MMBtu	4.01	3.95
Fair value, net	-1,800	-320
NYMEX Swap – Natural Gas 2015 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (MMbtu-gas)	8,983,560	3,755,184
Weighted-average fixed price per MMBtu	4.01	3.95
Fair value, net	-1,076	-908
NYMEX Swap – Natural Gas 2016 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (MMbtu-gas)	7,814,028	3,765,840
Weighted-average fixed price per MMBtu	4.01	3.96
Fair value, net	-719	-1,410
Basis Swap – Natural Gas Basis Differential 2013 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (MMbtu-gas)	'	9,000,003
Weighted-average fixed price per MMBtu	'	-0.71
Fair value, net	'	-4,448
NYMEX Swap – Oil 2013 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (Bbl-oil)	'	65,892
Weighted-average fixed price per Bbl	'	101.7
Fair value, net	'	546
NYMEX Swap – Oil 2014 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (Bbl-oil)	116,076	61,680
Weighted-average fixed price per Bbl	95.19	97
Fair value, net	-53	276
NYMEX Swap – Oil 2015 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (Bbl-oil)	71,568	58,164
Weighted-average fixed price per Bbl	92.73	93.4
Fair value, net	281	168
NYMEX Swap – Oil 2016 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (Bbl-oil)	65,568	53,892
Weighted-average fixed price per Bbl	90.33	91.1
Fair value, net	340	125
2013 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value, net	'	-2,632
2014 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value, net	-1,853	-44
2015 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value, net	-795	-740
2016 [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value, net	-379	-1,285
Natural Gas Swaps [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (MMbtu-gas)	27,125,160	15,592,341
Weighted-average fixed price per MMBtu	4.01	3.95
Fair value, net	-3,595	-1,368
Natural Gas Basis Swaps [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (MMbtu-gas)	'	9,000,003
Weighted-average fixed price per MMBtu	'	-0.71
Fair value, net	'	-4,448
Crude Oil Swaps [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Contract volumes (Bbl-oil)	253,212	239,628
Weighted-average fixed price per Bbl	93.23	96.09
Fair value, net	$568	$1,115

Derivative_Financial_Instrumen5

Derivative Financial Instruments (Reconciliation Of Gross Amounts To Net Amounts) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Financial Instruments [Abstract]	'	'
Gross amounts of recognized assets	$706	$2,386
Gross amounts offset in the balance sheet	'	'
Net amounts of assets presented in the balance sheet	706	2,386
Gross amounts not offset in the balance sheet	-706	-2,386
Net amount	'	'
Gross amounts of recognized liabilities	3,733	7,087
Gross amounts offset in the balance sheet	'	'
Net amounts of liabilities presented in the balance sheet	3,733	7,087
Gross amounts not offset in the balance sheet	-706	-2,386
Net amount	$3,027	$4,701

Financial_Instruments_Narrativ

Financial Instruments (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Common Class A [Member]	'	'	'	'
Fair Value Measurements [Line Items]	'	'	'	'
Equity investment member interest number	484,505	'	'	'
Fair value, per unit	$0.79	'	'	'
Common Class B [Member]	'	'	'	'
Fair Value Measurements [Line Items]	'	'	'	'
Equity investment member interest number	5,918,894	'	'	'
Fair value, per unit	$2.40	'	'	'
Series A Preferred Stock [Member]	'	'	'	'
Fair Value Measurements [Line Items]	'	'	'	'
Preferred stock, shares outstanding	7,250	7,250	6,000	6,000
Cumulative Redeemable Preferred Stock, fair value	$30,900,000	$91,300,000	'	'
Cumulative Redeemable Preferred Stock, carrying value	$23,828,000	$73,152,000	$56,736,000	$50,622,000
LIBOR interest rate and risk premium used to discount cash flows for determining fair value	12.90%	7.10%	'	'

Financial_Instruments_Assets_a

Financial Instruments (Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Equity investment	$14,588	$7,820
Derivative financial instruments-assets	706	2,386
Derivative financial instruments-liabilities	-3,733	-7,087
Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Equity investment	14,588	7,820
Derivative financial instruments-assets	706	2,386
Derivative financial instruments-liabilities	-3,733	-7,087
Assets and liabilities fair value, Total	11,561	3,119
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Equity investment	14,205	6,984
Assets and liabilities fair value, Total	14,205	6,984
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Equity investment	383	836
Derivative financial instruments-assets	706	2,386
Derivative financial instruments-liabilities	-3,733	-7,087
Assets and liabilities fair value, Total	($2,644)	($3,865)

Equity_Investment_Narrative_De

Equity Investment (Narrative) (Details) (CEP [Member], Sanchez Energy Partners I, LP [Member], USD $)	0 Months Ended
	Aug. 09, 2013
Business Acquisition [Line Items]	'
Cash consideration	$20,090,876
Aggregate purchase price	$30,400,000
Class B Units [Member]	'
Business Acquisition [Line Items]	'
Unit consideration	4,724,407
Class A Units [Member]	'
Business Acquisition [Line Items]	'
Unit consideration	1,130,512
Class Z Unit [Member]	'
Business Acquisition [Line Items]	'
Unit consideration	1

Equity_Investment_Effect_of_Ma

Equity Investment (Effect of Mark to Market Gains (Losses) on Equity Investment) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Option, Quantitative Disclosures [Line Items]	'	'	'
Mark to market gains (losses) on equity investment	$6,768	($5,174)	($4,607)
Equity Method Investments [Member]	'	'	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'	'	'
Mark to market gains (losses) on equity investment	$6,768	($5,174)	($4,607)

Equity_Investment_Summarized_C

Equity Investment (Summarized Condensed Financial Information of CEP) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Schedule Of Summarized Financial Information Of Equity Investee [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Gross revenues

$18,039

$18,614

$19,594

$16,053

$15,853

$13,697

$11,124

$14,321

$72,300

$54,995

$85,126

CEP [Member]

'

'

'

'

'

'

'

'

'

'

'

Schedule Of Summarized Financial Information Of Equity Investee [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Gross revenues

'

'

'

'

'

'

'

'

46,381

59,335

105,217

Gross profit (loss)

'

'

'

'

'

'

'

'

-25,589

[1]

-80,964

[1]

29,453

[1]

Net income (loss) from continuing operations

'

'

'

'

'

'

'

'

-25,857

[2]

-9,462

[2]

'

Net income (loss)

'

'

'

'

'

'

'

'

($28,543)

($86,543)

$19,586

[1]

Equals revenues less operating expenses

[2]

Net income from continuing operations is not available for 2011

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Schedule of Changes in Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligations [Abstract]	'		'
Asset retirement obligations at beginning of period	$10,868	[1]	$10,087	[1]
Liabilities incurred	533		160
Liabilities settled	-88		-111
Acquistions	538		'
Accretion	811		743
Revision of estimates	566		-11
Asset retirement obligations at end of period	13,228		10,868	[1]
Current portion of asset retirement obligations	129		'
Noncurrent portion of asset retirement obligations at end of period	$13,099		$10,868
[1]	Amounts in the table do not include the asset retirement obligations of KPC which was divested by the Company during 2012.

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)

1 Months Ended

6 Months Ended

7 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2010

Jun. 30, 2011

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2012

Jun. 30, 2011

Jan. 31, 2011

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

item

Quest Eastern Resource LLC [Member]

Quest Eastern Resource LLC [Member]

Quest Eastern Resource LLC [Member]

Quest Eastern Resource LLC [Member]

Quest Eastern Resource LLC [Member]

Citibank, N.A. and Royal Bank of Canada [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Letter of Credit [Member]

London Interbank Offered Rate (LIBOR) [Member]

Base Rate [Member]

London Interbank Offered Rate (LIBOR) [Member]

Base Rate [Member]

Citibank, N.A. and Royal Bank of Canada [Member]

Citibank, N.A. and Royal Bank of Canada [Member]

Citibank, N.A. and Royal Bank of Canada [Member]

Citibank, N.A. and Royal Bank of Canada [Member]

Citibank, N.A. and Royal Bank of Canada [Member]

Citibank, N.A. and Royal Bank of Canada [Member]

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maximum borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$200,000,000

'

Credit facility, borrowing base

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

115,000,000

90,000,000

'

'

Credit facility, outstanding borrowings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

92,000,000

1,300,000

Credit facility, amount available for additional borrowings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21,700,000

'

Ratio of current assets to current liabilities

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ratio of consolidated EBITDAX to consolidated interest charges

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rato of consolidated funded debt to consolidated EBITDAX

'

'

'

3.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Basis spread on variable rate

'

'

'

'

'

'

'

'

'

'

'

'

2.50%

1.50%

3.25%

2.25%

'

'

'

'

Interest rate at period end

'

'

'

'

'

'

'

'

'

'

'

3.17%

'

'

'

'

'

'

'

'

Repayment of deficiency under option one

'

'

'

'30 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayment of deficiency under option two

'

'

'

6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum percentage of sale of assets

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of oil and gas properties

28,000,000

16,600,000

44,600,000

'

'

'

'

'

'

44,600,000

'

'

'

'

'

'

'

'

'

'

Purchase price of assets

'

'

'

'

'

'

'

'

'

41,600,000

'

'

'

'

'

'

'

'

'

'

Payments made from sale proceeds

'

'

'

'

'

'

'

4,300,000

9,300,000

'

21,200,000

'

'

'

'

'

'

'

'

'

Repayments of long-term lines of credit stock value

'

'

'

'

'

'

'

'

'

843,000

'

'

'

'

'

'

'

'

'

'

Settlement of outstanding loan balance common stock

'

'

'

29,915,951

21,309,159

'

'

'

'

141,186

'

'

'

'

'

'

'

'

'

'

Common stock fair value

'

'

'

299,000

213,000

'

'

'

'

744,000

'

'

'

'

'

'

'

'

'

'

Escrowed funds released

'

'

'

'

5,700,000

'

5,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Escrow deposit retained by Company

'

'

'

'

1,300,000

'

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of long-term debt

'

'

'

'

'

'

4,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain on forgiveness of debt

'

'

'

'

255,000

1,647,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued interest forgiven

'

'

'

'

'

'

'

'

'

799,000

'

'

'

'

'

'

'

'

'

'

Deferred finance costs

'

'

'

1,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred financing costs amortization period

'

'

'

'4 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized deferred financing costs

'

'

'

$1,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LongTerm_Debt_Summary_of_LongT

Long-Term Debt (Summary of Long-Term Debt) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Line of Credit Facility [Line Items]	'	'
Total long-term debt	$92,000	$57,500
Secured Debt [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Borrowing Base Facility	92,000	57,500
Total long-term debt	$92,000	$57,500

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Abstract]	'	'	'
Provision (benefit) for income taxes	$180,000	$0	$0
2011 IRS Settlement	30,000	'	'
Current tax expense	70,000	'	'
Operating loss carry forwards	237,000,000	'	'
Federal NOL carryforwards 382 limit	228,000,000	'	'
Federal NOL carryforwards that will expire	210,000,000	'	'
Recognized built in loss ownership change recognized period	'5 years	'	'
Recognized built-in-loss	96,100,000	96,100,000	96,100,000
Operating loss carry forward amortized period	3,500,000	'	'
NOL carryforwards recorded as deferred tax asset	27,000,000	'	'
Recognized built-in-losses that will carryforward	92,600,000	'	'
Recognized built-in-loss that will expire	89,400,000	'	'
Operating loss carry forwards deferred tax asset	$3,200,000	'	'

Income_Taxes_Reconciliation_Of

Income Taxes (Reconciliation Of Federal Income Taxes At Federal Rates To Actual Provision For Income Taxes) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Abstract]	'	'	'
Income tax expense (benefit) at statutory rate	($3,100,000)	($16,650,000)	$7,011,000
State income tax expense (benefit), net of federal	19,000	958,000	647,000
2011 IRS Settlement	30,000	'	'
Other	496,000	1,650,000	2,942,000
IRC Section 382 limitation	2,575,000	30,491,000	-2,135,000
Change in valuation allowance	160,000	-16,449,000	-8,465,000
Total tax expense (benefit)	$180,000	$0	$0

Income_Taxes_Summary_Of_Deferr

Income Taxes (Summary Of Deferred Tax Assets and Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current deferred income tax assets	'	'
Unrealized loss for commodity derivative recorded for book, not for tax	$722	$1,658
Accrued liabilities	1,038	1,047
Allowance for bad debts	72	72
Other	277	630
Total current deferred income tax assets	2,109	3,407
Noncurrent deferred income tax assets	'	'
Unrealized loss for commodity derivative recorded for book, not for tax	669	983
Partnership basis differences	6,287	6,037
Property and equipment	37,849	45,733
Asset retirement obligations	2,173	1,871
Net operating loss carryforwards	14,943	18,459
Other carryforwards	2,264	1,516
Total noncurrent deferred income tax assets	64,185	74,599
Total deferred income tax assets	66,294	78,006
Current deferred income tax liabilities	'	'
Unrealized gain for commodity derivative recorded for book, not for tax	-20	-11,905
Total current deferred income tax liabilities	-20	-11,905
Noncurrent deferred income tax liabilities	'	'
Unrealized gain for commodity derivative recorded for book, not for tax	-420	-407
Total noncurrent deferred income tax liabilities	-420	-407
Total deferred income tax liabilities	-440	-12,312
Net deferred income tax assets	65,854	65,694
Valuation allowance	-65,854	-65,694
Total deferred tax asset (liability)	'	'

Redeemable_Preferred_Stock_and2

Redeemable Preferred Stock and Warrants (Narrative) (Details) (USD $)	1 Months Ended				12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2012	Sep. 21, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
					D
Summary Activity [Line Items]	'	'	'	'	'	'	'
Warrants issued to purchase common stock	'	4,577,464	3,076,923	19,047,619	'	'	'
Proceeds from issuance of preferred stock and warrants	'	$6,500	$6,000	$60,000	'	$12,500	'
Warrant exercise price	2.8	1.42	1.95	'	2.8	1.42	'
Percentage of additional liquidation preference rate	'	'	'	'	'	14.00%	'
Warrant exercisable period	'	'	'	'	'	'90 months	'
Percentage of market price of common stock exceeds exercise price	300.00%	'	'	'	300.00%	'	'
Maximum percentage of warrants can be exercised to purchase shares	50.00%	'	'	'	50.00%	'	'
Maximum number of shares can be issued upon exercise of warrants	750,000	'	'	'	750,000	'	'
Common stock trading days	'	'	'	'	20	'	'
Issuance of stock	'	'	'	'	10,612	20,445	4,844
Warrants exercisable for common stock	22,241,333	'	'	'	22,241,333	'	'
Series B Voting Preferred Stock shares issued per unit	0.01	'	'	'	0.01	'	'
Risk premium	13.70%	'	'	'	'	'	'
Interest expense	'	'	'	'	3,740	10,454	10,154
Minimum [Member]	'	'	'	'	'	'	'
Summary Activity [Line Items]	'	'	'	'	'	'	'
Warrant exercise price	6.39	'	'	'	6.39	'	'
Maximum [Member]	'	'	'	'	'	'	'
Summary Activity [Line Items]	'	'	'	'	'	'	'
Warrant exercise price	3.23	'	'	'	3.23	'	'
Warrants [Member]	'	'	'	'	'	'	'
Summary Activity [Line Items]	'	'	'	'	'	'	'
Issuance of stock, shares	1,123,981	'	'	'	'	'	'
Issuance of stock	1,500	'	'	'	'	'	'
Series A Preferred Stock [Member]	'	'	'	'	'	'	'
Summary Activity [Line Items]	'	'	'	'	'	'	'
Issuance of cumulative preferred stock	'	'	'	6,000	'	'	'
Series A Preferred Stock	'	650	600	'	'	1,250	'
Liquidation Value of Series A Preferred Stock, Issuance	'	6,500	6,000	'	'	12,500	'
Preferred stock, cumulative dividend rate	'	12.00%	'	'	'	'	'
Redemption date of preferred stock	'	'	'	'	21-Mar-18	'	'
Redemption rate on mandatory date	'	100.00%	'	'	'	100.00%	'
Redemption rate before mandatory date	'	110.00%	'	'	'	110.00%	'
Mandatorily redeemable preferred stock	64,523	'	'	'	64,523	'	'
Interest expense	497	'	'	'	'	'	'
Series B Preferred Stock [Member]	'	'	'	'	'	'	'
Summary Activity [Line Items]	'	'	'	'	'	'	'
Issuance of cumulative preferred stock	113,521	265,095	'	190,476.19	113,521	265,095	'
Maximum voting stock applicable for Series B Preferred Stock holder	'	'	45.00%	'	'	'	'
Issuance of stock	'	'	'	'	$1	$1	'

Redeemable_Preferred_Stock_and3

Redeemable Preferred Stock and Warrants (Changes in Series A Preferred Stock and Associated Warrants) (Details) (USD $)	1 Months Ended		12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Aug. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Temporary Equity [Line Items]	'	'	'	'	'
Number of Outstanding Warrants, beginning balance	'	'	34,336,414	21,566,245	19,584,205
Number of Outstanding Warrants, Issuance	'	'	'	7,654,387	'
Number of Outstanding Warrants, Accrued dividends	'	'	8,066,270	5,115,782	1,982,040
Number of Outstanding Warrants, Warrant Exchange	'	'	-22,241,333	'	'
Number of Outstanding Warrants, Ending Balance	34,336,414	'	20,161,351	34,336,414	21,566,245
Weighted Average Exercise Price of Warrants, Beginning Balance	'	'	$2.66	$3.23	$3.16
Weighted Average Exercise Price of Warrants, Issuance	'	'	'	$1.63	'
Weighted Average Exercise Price of Warrants, Accrued dividends	'	'	$1.42	$1.78	$3.92
Weighted Average Exercise Price of Warrants, Warrant Exchange	'	'	$3.23	'	'
Weighted Average Exercise Price of Warrants, Ending Balance	$2.66	'	$1.54	$2.66	$3.23
Series A Preferred Stock [Member]	'	'	'	'	'
Temporary Equity [Line Items]	'	'	'	'	'
Carrying Value of Series A Preferred Stock, beginning balance	'	'	$73,152	$56,736	$50,622
Carrying Value of Series A Preferred Stock, Issuance	'	'	'	8,428	'
Carrying Value of Series A Preferred Stock, Accrued dividends	'	'	7,479	5,750	4,534
Carrying Value of Series A Preferred Stock, Accretion	'	'	3,283	2,238	1,580
Carrying Value of Series A Preferred Stock, Warrant Exchange	'	'	-60,086	'	'
Carrying Value of Series A Preferred Stock, ending balance	73,152	'	23,828	73,152	56,736
Carrying Value of Series A Preferred Stock in Liabilities, Warrant Exchange	'	'	64,443	'	'
Carrying Value of Series A Preferred Stock in Liabilities, Accretion	'	'	80	'	'
Carrying Value of Series A Preferred Stock in Liabilities	'	'	64,523	'	'
Beginning balance, preferred shares	'	'	7,250	6,000	6,000
Number of Outstanding Series A Preferred Shares, Issuance	650	600	'	1,250	'
Ending balance, preferred shares	7,250	'	7,250	7,250	6,000
Liquidation Value of Series A Preferred Stock, beginning balance	'	'	91,342	69,759	61,980
Liquidation Value of Series A Preferred Stock, Issuance	6,500	6,000	'	12,500	'
Liquidation Value of Series A Preferred Stock, Accrued dividends	'	'	11,047	9,083	7,779
Liquidation Value of Series A Preferred Stock, Accrued dividends recorded as interest	'	'	417	'	'
Liquidation Value of Series A Preferred Stock, Accretion	'	'	102,806	'	'
Liquidation Value of Series A Preferred Stock, ending balance	$91,342	'	'	$91,342	$69,759

Redeemable_Preferred_Stock_and4

Redeemable Preferred Stock and Warrants (Changes to Additional Paid in Capital as Result of Warrants Issued) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Activity [Line Items]	'	'	'
Total change in APIC due to warrants issued	$3,984	$7,405	$3,763
White Deer [Member]	'	'	'
Summary Activity [Line Items]	'	'	'
Warrants issued in conjunction with issuance of Series A Preferred Stock	'	4,071	'
Warrants issued in conjunction with paid-in-kind dividends	3,984	3,334	3,245
Total change in APIC due to warrants issued	$3,984	$7,405	$3,245

Recovered_Sheet1

Equity and Earnings Per Share (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity And Earnings Per Share [Line Items]	'	'	'
Common shares pursuant to an at-the-market issuance sales	$100,000,000	'	'
Long -Term Incentive Plan [Member]	'	'	'
Equity And Earnings Per Share [Line Items]	'	'	'
Shares authorized for future stock and option awards	10,850,000	'	'
Vesting percentage	33.00%	'	'
Award vesting period	'3 years	'	'
Award vesting period in conjunction with Company's annual bonus program	'1 year	'	'
Award vesting period for non-employee directors	'1 year	'	'
Shares available under plan for future stock awards and options	7,208,111	'	'
Expected option life-years	'4 years	'	'
Long -Term Incentive Plan [Member] | Minimum [Member]	'	'	'
Equity And Earnings Per Share [Line Items]	'	'	'
Expiration period for options granted	'5 years	'	'
Long -Term Incentive Plan [Member] | Maximum [Member]	'	'	'
Equity And Earnings Per Share [Line Items]	'	'	'
Expiration period for options granted	'6 years	'	'
Expected option life-years	'	'	'6 years
Long -Term Incentive Plan [Member] | Restricted Shares [Member]	'	'	'
Equity And Earnings Per Share [Line Items]	'	'	'
Unrecognized compensation expense for non-vested awards	444,000	'	'
Weighted average period of recognition for unrecognized compensation expense	'1 year 2 months 23 days	'	'
Share based compensation restricted shares, granted	641,902	1,295,112	487,500
Long -Term Incentive Plan [Member] | Stock Options [Member]	'	'	'
Equity And Earnings Per Share [Line Items]	'	'	'
Weighted average period of recognition for unrecognized compensation expense	'1 year 3 months 7 days	'	'
Weighted average remaining term of options outstanding	'3 years 6 months 7 days	'	'
Weighted average remaining term of options exercisable	'3 years 29 days	'	'
Aggregate intrinsic value of options outstanding	'	'	'
Aggregate intrinsic value of options exercisable	'	'	'
Expected option life-years	'4 years	'5 years	'
Unrecognized compensation expense for stock options	$665,000	'	'
Number of options granted	584,949	1,303,653	799,400
Share based compensation exercise price	$1.77	1.8	3.63
Long -Term Incentive Plan [Member] | Stock Options [Member] | Minimum [Member]	'	'	'
Equity And Earnings Per Share [Line Items]	'	'	'
Expected option life-years	'	'	'5 years

Recovered_Sheet2

Equity and Earnings per Share (Summary of Changes in Non-Vested Restricted Shares) (Details) (Long -Term Incentive Plan [Member], Restricted Shares [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Long -Term Incentive Plan [Member] | Restricted Shares [Member]	'		'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'	'
Number of Non-Vested Restricted Shares, Beginning balance	1,479,566		579,210	375,358
Number of Non-Vested Restricted Shares, Granted	641,902		1,295,112	487,500
Number of Non-Vested Restricted Shares, Vested	-452,529		-275,900	-80,554
Number of Non-Vested Restricted Shares, Cancelled/Forfeited	-1,053,673	[1]	-118,856	-203,094
Number of Non-Vested Restricted Shares, Ending balance	615,266		1,479,566	579,210
Weighted Average Grant-Date Fair Value, Beginning Balance	$2.16		$3.33	$4.83
Weighted Average Grant-Date Fair Value, Granted	$1.75		$2.01	$2.90
Weighted Average Grant-Date Fair Value, Vested	$2.79		$3.23	$5.91
Weighted Average Grant-Date Fair Value, Cancelled/Forfeited	$1.79	[1]	$3.76	$5.08
Weighted Average Grant-Date Fair Value, Ending Balance	$1.89		$2.16	$3.33
Shares cancelled	787,414		'	'
Restricted stock compensation expense	$500		'	'
[1]	787,414 shares were cancelled with an associated accelerated stock compensation expense of approximately $500,000.

Equity_and_Earnings_per_Share_1

Equity and Earnings per Share (Summary of Changes in the Stock Options Outstanding) (Details) (Long -Term Incentive Plan [Member], Stock Options [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Long -Term Incentive Plan [Member] | Stock Options [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock Options, Beginning Balance	2,170,283	1,056,850	567,050
Stock Options, Granted	584,949	1,303,653	799,400
Stock Options, Exercised	'	'	-20,000	[1]
Stock Options, Forfeited or expired	-448,813	-190,220	-289,600
Stock Options, Ending Balance	2,306,419	2,170,283	1,056,850
Stock Options, Options exercisable	989,037	467,189	310,922
Weighted Average Exercise Price per Share, Options outstanding	$2.45	$3.59	$4.17
Weighted Average Exercise Price per Share, Granted	$1.77	$1.80	$3.63
Weighted Average Exercise Price per Share, Exercised	'	'	$3.29	[1]
Weighted Average Exercise Price per Share, Forfeited or expired	$1.92	$4.30	$4.07
Weighted Average Exercise Price per Share, Option outstanding	$2.38	$2.45	$3.59
Weighted Average Exercise Price per Share, Options exercisable	$3.03	$4.10	$5.57
Weighted Average Grant Date Fair Value per Option	$0.89	$1.07	$2.15
Value received upon exercise of the options	'	'	$66
Intrinsic value of exercised options	'	'	$34
[1]	The Company received $66,000 upon exercise of these options which had a total intrinsic value of $34,000 at the exercise dates.

Equity_and_Earnings_per_Share_2

Equity and Earnings per Share (Weighted-Average Assumptions to Estimate the Fair Value of Stock Options Granted) (Details) (Long -Term Incentive Plan [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Expected option life-years	'4 years	'	'
Maximum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Expected option life-years	'	'	'6 years
Stock Options [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Expected option life-years	'4 years	'5 years	'
Volatility, Minimum	64.00%	74.30%	74.40%
Volatility, Maximum	82.70%	76.10%	77.00%
Risk-free interest rate, Minimum	0.60%	0.90%	0.90%
Risk-free interest rate, Maximum	1.40%	1.30%	2.00%
Dividend yield	'	'	'
Stock Options [Member] | Minimum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Expected option life-years	'	'	'5 years
Fair value per share	$0.82	$0.87	$1.43
Stock Options [Member] | Maximum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Fair value per share	$1.03	$1.88	$4.53

Equity_and_Earnings_per_Share_3

Equity and Earnings per Share (Total Share-Based Compensation Covering Stock Awards and Options) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity And Earnings Per Share [Abstract]	'	'	'
Stock-based compensation	$3,177	$2,224	$1,258

Equity_and_Earnings_per_Share_4

Equity and Earnings per Share (Reconciliation of Numerator and Denominator Used in Basic and Diluted Per Share Calculations) (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Earnings Per Common Share [Line Items]	'		'		'
Denominator for basic earnings per share	25,068,574	[1]	13,595,843	[1]	8,785,551	[1]
Unvested share-based awards	'		'		127,600
Warrants	'		'		6,089,339
Stock options	'		'		47,230
Denominator for diluted earnings per share	25,068,574		13,595,843		15,049,720
Securities excluded from earnings per share calculation	'		'		'
Securities excluded from earnings per share calculation	'		149,988		14,998
Stock Options [Member]	'		'		'
Securities excluded from earnings per share calculation	'		'		'
Securities excluded from earnings per share calculation	2,306,419		2,170,283		1,056,850
Warrants [Member]	'		'		'
Securities excluded from earnings per share calculation	'		'		'
Securities excluded from earnings per share calculation	17,929,512		33,086,615		1,830,464
[1]	Includes vested common shares in the Company’s deferred compensation plan and vested deferred restricted stock units, both of which will deliver shares to participants at a later date. Although shares have not been delivered on these awards, all conditions for issuance and delivery have been met. Pursuant to FASB ASC 260-10-45-13, such shares are to be included in the denominator in calculating basic earnings per share.

Equity_and_Earnings_per_Share_5

Equity and Earnings per Share (Schedule of Common Stock Issuance) (Details) (USD $)	12 Months Ended		1 Months Ended			12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Aug. 31, 2012	Feb. 29, 2012	Dec. 31, 2013	Dec. 31, 2012
			White Deer [Member]	White Deer [Member]	White Deer [Member]	Universal Shelf Registration Statement [Member]	Universal Shelf Registration Statement [Member]
Equity And Earnings Per Share [Line Items]	'	'	'	'	'	'	'
Gross proceeds	$4,076	$20,724	$6,500	$6,000	$7,500	$4,076	$724
Common shares sold	'	'	4,577,464	3,076,923	2,180,233	2,592,313	446,098

Commitments_and_Contingencies_1

Commitments and Contingencies (Narrative) (Details) (USD $)	1 Months Ended		12 Months Ended			1 Months Ended
	Dec. 31, 2012	Jan. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jul. 31, 2011	Nov. 30, 2010	Nov. 30, 2010
						Oklahoma [Member]	Jerry Cash [Member]	David Grose [Member]
Commitment And Contingencies [Line Items]	'	'	'	'	'	'	'	'
Funded settlements	$4,500,000	$3,000,000	'	'	'	$5,600,000	'	'
Total settlement (against) awarded to amount	'	'	'	-7,500,000	'	'	5,000,000	1,000,000
Litigation reserve expenses	'	'	0	0	11,592,000	'	'	'
Rental expense	'	'	$10,800,000	$12,400,000	$13,600,000	'	'	'

Commitments_and_Contingencies_2

Commitments and Contingencies (Future Minimum Rental Payments Under All Non-Cancelable Operating Leases) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitments and Contingencies [Abstract]	'
2014	$3,558
2015	2,468
2016	847
2017	373
2018	10
Thereafter	'
Total minimum lease obligations	$7,256

Impairment_of_Oil_and_Gas_Prop1

Impairment of Oil and Gas Properties (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Impairment of Oil and Gas Properties [Abstract]	'	'	'
Impairment of oil and gas properties	$0	$5,919	$0

Discontinued_Operations_Narrat

Discontinued Operations (Narrative) (Details) (USD $)	12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Sep. 28, 2012	Dec. 31, 2012		Dec. 31, 2011
		mi	KPC Pipeline [Member]	KPC Pipeline [Member]		KPC Pipeline [Member]
			Discontinued Operations [Member]	Discontinued Operations [Member]		Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'		'
Purchase and sale agreement date	28-Sep-12	'	'	'		'
Disposal group Purchase Price	'	'	$53,500,000	'		'
Disposal group purchase price, received	'	'	53,400,000	'		'
Additional payment to be received	'	'	'	1,000,000		'
Interstate natural gas pipeline, length	'	1,120	'	'		'
Carrying value of the net assets sold	'	'	57,000,000	'		'
Gain (loss) on disposal of assets	'	'	'	-5,437,000	[1]	3,000	[1]
Closing-related costs	'	'	'	1,900,000		'
Legal, professional, and investment banking fees	'	'	'	1,000,000		'
Severance costs	'	'	'	505,000		'
Site cleanup costs	'	'	'	$350,000		'
[1]	Includes a loss of $5.4 million from the disposal of KPC.

Discontinued_Operations_Result

Discontinued Operations (Results of Discontinued Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'		'
Total income from discontinued operations	($2,855)		$643
KPC Pipeline [Member] | Discontinued Operations [Member]	'		'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'		'
Interstate pipeline revenue	8,934		11,183
Pipeline expense	-2,825		-5,219
Depreciation and amortization	-2,537		-3,574
Gain (loss) on disposal of assets	-5,437	[1]	3	[1]
General and administrative expenses	-945		-1,194
Interest expense	-45		-556
Income from discontinued operations before income taxes	-2,855		643
Income taxes	'		'
Total income from discontinued operations	($2,855)		$643
[1]	Includes a loss of $5.4 million from the disposal of KPC.

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Supplemental Cash Flow Information Summary Of Supplemental Cash Flow Information [Abstract]	'	'	'
Cash paid for interest	$2,780	$7,292	$8,623
Cash paid for income taxes	100	'	'
Non-cash investing activity	'	'	'
Common stock issued for purchase of equity investment	'	'	4,100
Common stock issued for purchase of oil and gas properties	6,728	'	'
Common stock issued to fund 401K and deferred compensation plans	931	'	'
Common stock issued to repurchase and retire outstanding warrants	1,528	'	'
Warrants issued for purchase of equity investment	'	'	518
Equity securities received on the sale of oil and gas properties	'	'	5,875
Property additions financed through accounts payable and accrued liabilities	1,010	239	830
Additions to property and equipment by recognizing asset retirement obligations	1,099	159	4,067
Non-cash financing activity	'	'	'
Reduction of debt through conveyance of financial securities received from sale of oil and gas properties	'	'	5,729
Reduction of debt through issuance of common stock	'	'	843
Issuance of preferred stock and warrants in lieu of cash dividends	11,464	9,083	7,779
Accretion of discount on redeemable preferred stock reflected in interest expense	80	'	'
Accretion of discount on redeemable preferred stock	$3,283	$2,238	$1,580

Recovered_Sheet3

Profit Sharing and Deferred Compensation Plan (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013
Schedule Of Defined Contribution Plans Disclosures [Line Items]	'
Maximum percentage of employee contribution to company	100.00%
Number of shares transferred to profit sharing plan	404,805
Shares issued to 401(k) plan	325,005
Shares purchased on the open market	79,800
Year 1 [Member]	'
Schedule Of Defined Contribution Plans Disclosures [Line Items]	'
Vesting percentage of company contributions	33.00%
Year 2 [Member]	'
Schedule Of Defined Contribution Plans Disclosures [Line Items]	'
Vesting percentage of company contributions	67.00%
Year 3 [Member]	'
Schedule Of Defined Contribution Plans Disclosures [Line Items]	'
Vesting percentage of company contributions	100.00%
Minimum [Member]	'
Schedule Of Defined Contribution Plans Disclosures [Line Items]	'
Percentage of employee contribution to company	3.00%
Maximum [Member]	'
Schedule Of Defined Contribution Plans Disclosures [Line Items]	'
Percentage of employee contribution to company	6.00%

Profit_Sharing_And_Deferred_Co1

Profit Sharing And Deferred Compensation Plan (Profit Sharing Plan Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Profit Sharing And Deferred Compensation Plan [Abstract]	'	'	'
401(k) profit sharing plan cost	$662	$235	$492

Profit_Sharing_And_Deferred_Co2

Profit Sharing And Deferred Compensation Plan (Schedule Of Deferred Compensation) (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Profit Sharing And Deferred Compensation Plan [Abstract]	'
Shares of common stock contributed	324,522
Fair value of common stock contributed	$473

Supplemental_Financial_Informa2

Supplemental Financial Information - Quarterly Financial Data (Schedule of Quarterly Financial Information) (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Financial Information-Quarterly Financial Data [Abstract]	'		'		'		'		'		'		'		'		'	'	'
Total revenues	$18,039		$18,614		$19,594		$16,053		$15,853		$13,697		$11,124		$14,321		$72,300	$54,995	$85,126
Operating income (loss)	-3,873	[1]	-1,679	[1]	-2,019	[1]	-3,727	[1]	-6,649	[1]	-11,409	[1]	-10,352	[1]	-7,501	[1]	-11,298	-35,911	-3,138
Net income (loss)	($7,377)		($645)		$6,880		($7,894)		($11,237)		($25,174)		($18,508)		$7,347		($9,036)	($47,572)	$20,030
Net income (loss) per share common share	'		'		'		'		'		'		'		'		'	'	'
Basic	($0.38)		($0.18)		$0.13		($0.50)		($0.89)		($1.94)		($1.71)		$0.43		($0.93)	($4.33)	$1.21
Diluted	($0.38)		($0.18)		$0.13		($0.50)		($0.89)		($1.94)		($1.71)		$0.37		($0.93)	($4.33)	$0.71
[1]	Total revenue less total costs and expenses.

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Gas Producing Activities (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil reserve portion percent reported	23.00%	19.00%	5.00%
Gas reserve portion percent reported	77.00%	'	'
CEP [Member]	'	'	'
Voting interest	21.30%	26.50%	26.40%

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Gas Producing Activities (Aggregate Capitalized Costs Related to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and gas properties and related equipment (successful efforts method)	'	'
Proved	$405,895	$353,093
Unproved	4,862	31
Net capitalized costs, gross	410,757	353,124
Accumulated depreciation, depletion and amortization	-268,846	-245,593
Net capitalized costs	141,911	107,531
CEP [Member]	'	'
Oil and gas properties and related equipment (successful efforts method)	'	'
Proved	135,642	156,851
Unproved	338	366
Materials, supplies and land	385	402
Net capitalized costs, gross	136,365	157,619
Accumulated depreciation, depletion and amortization	-105,481	-125,787
Net capitalized costs	$30,884	$31,832

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Gas Producing Activities (Costs Incurred for Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Proved property acquisition costs	$8,023	[1]	$151	[1]	$223	[1]
Unproved property acquisition costs	8,567		52		630
Exploration costs	'		'		'
Development costs	40,004		12,506		23,825
Costs incurred for oil and gas property acquisition, exploration and development activities that have been capitalized	56,594		12,709		24,678
CEP [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Proved property acquisition costs	4,262	[1],[2]	20	[1],[2]	-74	[1],[2]
Unproved property acquisition costs	45	[2]	47	[2]	167	[2]
Exploration costs	'	[2]	'	[2]	'	[2]
Development costs	3,343	[2]	4,064	[2]	2,895	[2]
Costs incurred for oil and gas property acquisition, exploration and development activities that have been capitalized	$7,650	[2]	$4,131	[2]	$2,988	[2]
[1]	The amount is negative for CEP in 2011 as it represents a post-closing receipt from an acquisition made by CEP in December 2010.
[2]	Based on the Company’s pro-rata interest in CEP (disclosed above) assuming that the Company’s investment was made at the beginning of the period.

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Gas Producing Activities (Pro-Rata Results of Oil and Gas Producing Activities of Investment in CEP) (Details) (CEP [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CEP [Member]	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Revenues	$9,388	$12,330	$27,778
Lease operating expense	4,017	5,144	7,379
Cost of sales and production taxes	864	780	1,343
Exploration costs	'	'	35
Impairment of oil and gas properties	502	29	775
Depreciation, depletion and amortization	$4,041	$3,109	$5,845

Supplemental_Information_on_Oi6

Supplemental Information on Oil and Gas Producing Activities (Changes in Proved Developed and Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Mcf	Mcf	Mcf
Natural Gas [Member]	'	'	'
Proved reserves	'	'	'
Beginning Balance	69,661,273	118,220,188	130,462,031
Purchase of reserves in place	98,822	'	'
Extensions, discoveries, and other additions	1,122,511	1,867,365	1,752,746
Sale of reserves	'	'	-754,479
Revisions of previous estimates	30,246,006	-34,037,402	5,068,946
Production	-14,521,385	-16,388,878	-18,309,056
Ending Balance	86,607,227	69,661,273	118,220,188
Proved developed reserves	'	'	'
Ending Balance	85,006,592	69,661,273	117,406,577
Oil [Member]	'	'	'
Proved reserves	'	'	'
Beginning Balance	2,691,568	1,073,921	744,266
Purchase of reserves in place	554,892	'	'
Extensions, discoveries, and other additions	1,911,959	617,854	54,761
Revisions of previous estimates	-585,342	1,095,656	352,981
Production	-192,474	-95,863	-78,087
Ending Balance	4,380,603	2,691,568	1,073,921
Proved developed reserves	'	'	'
Ending Balance	2,705,664	1,804,057	1,040,309

Supplemental_Information_on_Oi7

Supplemental Information on Oil and Gas Producing Activities (Changes in Proved Developed and Undeveloped Reserves of CEP) (Details) (Natural Gas and Oil [Member], CEP [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Mcf	Mcf	Mcf
Natural Gas and Oil [Member] | CEP [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Beginning Balance	24,640,000	53,151,000	44,618,000
Decrease in pro rata ownership	-4,835,000	'	'
Purchase of reserves in place	1,523,000	'	'
Extensions, discoveries, and other additions	1,028,000	543,000	455,000
Sale of reserves	-10,519,000	-68,000	'
Revisions of previous estimates	9,527,000	-25,551,000	11,216,000
Production	-1,927,000	-3,435,000	-3,138,000
Ending Balance	19,437,000	24,640,000	53,151,000
Proved developed reserves	'	'	'
Ending Balance	16,748,000	23,850,000	40,295,000

Supplemental_Information_on_Oi8

Supplemental Information on Oil and Gas Producing Activities (Best Estimate of Required Data for Standardized Measure of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Future cash inflows	$720,924		$438,356		$592,796
Future production costs	315,079		218,707		312,410
Future development costs.	49,590		31,051		10,524
Future income tax expense	30,149		'		'
Future net cash flows	326,106		188,598		269,862
10% annual discount for estimated timing of cash flows	156,977		86,516		94,342
Standardized measure of discounted future net cash flows related to proved reserves	169,129		102,082		175,520
Standardized measure from continuing operations	169,129		102,082		175,520
CEP [Member]	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Future cash inflows	107,103	[1]	95,619	[1]	241,173	[1]
Future production costs	48,418	[1]	51,462	[1]	132,081	[1]
Future development costs.	8,668	[1]	2,948	[1]	25,705	[1]
Future net cash flows	50,017	[1]	41,209	[1]	83,387	[1]
10% annual discount for estimated timing of cash flows	19,406	[1]	17,446	[1]	40,964	[1]
Standardized measure of discounted future net cash flows related to proved reserves	30,611	[1],[2]	23,763	[1],[2]	42,423	[1],[2]
Standardized measure from continuing operations	30,611	[1],[2]	16,021	[1],[2]	42,423	[1],[2]
Standardized measure from discontinued operations	'		$7,742	[1],[2]	'
[1]	Represents the Company’s pro-rata share of its investment in CEP.
[2]	Represents the Company’s pro-rata share of its investment in CEP assuming that the Company’s investment was made at the beginning of each period presented.

Supplemental_Information_on_Oi9

Supplemental Information on Oil and Gas Producing Activities (Discounted Future Cash Flow Estimates do not Include Effects of Derivative Instruments) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Crude Oil and NGL [Member]	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average sales price	96.94	95.05	96.19
Natural Gas, Per Thousand Cubic Feet [Member]	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average sales price	3.67	2.76	4.12

Recovered_Sheet4

Supplemental Information on Oil and Gas Producing Activities (Principal Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proven Oil and Gas Properties) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]	'		'		'
Beginning balance	$102,082		$175,520		$159,261
Net changes in prices and production costs	37,826		18,071		11,876
Net changes in future development costs.	-30,462		-18,008		-1,154
Previously estimated development costs incurred	40,196		12,743		18,192
Sales of oil and gas produced, net	-29,604		-10,338		-32,751
Extensions and discoveries	23,514		7,724		3,045
Purchases of reserves in-place	6,401		'		'
Sales of reserves in-place	'		'		-1,104
Revisions of previous quantity estimates	49,926		-38,064		10,513
Net change in income taxes	-7,769		'		12,037
Accretion of discount	8,975		16,730		16,448
Timing differences and other	-31,956	[1]	-62,296	[1]	-20,843	[1]
Ending balance	169,129		102,082		175,520
Standardized measure from continuing operations	169,129		102,082		175,520
Standardized measure of discounted future net cash flows related to proved reserves	169,129		102,082		175,520
CEP [Member]	'		'		'
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]	'		'		'
Beginning balance	23,763	[2]	42,423	[2]	34,765	[2]
Net changes in prices and production costs	10,741	[2]	-5,095	[2]	38	[2]
Decrease in pro rata ownership	-4,664	[2]	'		'
Previously estimated development costs incurred	1,196	[2]	4,987	[2]	1,892	[2]
Sales of oil and gas produced, net	-4,525	[2]	-10,520	[2]	-7,810	[2]
Extensions and discoveries	6,069	[2]	3,336	[2]	2,157	[2]
Sales of reserves in-place	-489	[2]	-391	[2]	'
Revisions of previous quantity estimates	4,570	[2]	-22,034	[2]	11,243	[2]
Accretion of discount	1,910	[2]	4,258	[2]	3,477	[2]
Timing differences and other	-7,960	[1],[2]	6,799	[1],[2]	-3,339	[1],[2]
Ending balance	30,611	[2]	23,763	[2]	42,423	[2]
Standardized measure from continuing operations	30,611	[2],[3]	16,021	[2],[3]	42,423	[2],[3]
Standardized measure from discontinued operations	'		7,742	[2],[3]	'
Standardized measure of discounted future net cash flows related to proved reserves	$30,611	[2],[3]	$23,763	[2],[3]	$42,423	[2],[3]
[1]	The change in timing differences and other are related to revisions in the Company’s estimated time of production and development and the impact of changes in the relative proportion of oil versus natural gas in the Company’s total reserves.
[2]	Represents the Company’s pro-rata share of its investment in CEP assuming that the Company’s investment was made at the beginning of each period presented.
[3]	Represents the Company’s pro-rata share of its investment in CEP.