Abraxas Petroleum (AXAS) 10-K 17 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 17, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'ABRAXAS PETROLEUM CORP	'	'
Entity Central Index Key	'0000867665	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	92,932,137	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$181,392,208

CONSOLIDATED_BALANCE_SHEET

CONSOLIDATED BALANCE SHEET (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$5,205	$2,061
Accounts receivable:	'	'
Joint owners	15,493	8,883
Oil and gas production sales	16,625	10,887
Other	1,497	661
Total accounts receivable	33,615	20,431
Derivative asset	85	41
Other current assets	644	488
Total current assets	39,549	23,021
Oil and gas properties, full cost method of accounting:	'	'
Proved	564,755	563,317
Unproved properties excluded from depletion	0	2,089
Other property and equipment	38,959	37,833
Total	603,714	603,239
Less accumulated depreciation, depletion, and amortization	-423,069	-390,407
Total property and equipment, net	180,645	212,832
Deferred financing fees, net	2,140	3,397
Derivative asset	925	594
Other assets	391	763
Total assets	223,650	240,607
Current liabilities:	'	'
Accounts payable	52,793	42,387
Joint interest oil and gas production payable	23,810	6,947
Accrued interest	31	75
Other accrued expenses	1,231	962
Derivative liability	2,728	3,462
Current maturities of long-term debt	2,142	657
Total current liabilities	82,735	54,490
Long-term debt – less current maturities	41,790	124,101
Other liabilities	57	367
Derivative liability	2,274	3,568
Future site restoration	9,888	11,381
Total liabilities	136,744	193,907
Commitments and contingencies	0	0
Stockholders’ Equity:	'	'
Preferred stock, par value $.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding	0	0
Common stock, par value $.01 per share – authorized 200,000,000 shares; issued and outstanding 92,733,448 and 92,906,049	929	927
Additional paid-in capital	253,193	250,998
Accumulated deficit	-166,609	-205,256
Accumulated other comprehensive income (loss)	-607	31
Total stockholders’ equity	86,906	46,700
Total liabilities and stockholders’ equity	$223,650	$240,607

CONSOLIDATED_BALANCE_SHEET_Par

CONSOLIDATED BALANCE SHEET (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Stockholders’ Equity:	'	'
Preferred stock, par value (in dollars per share)	$0.01	$0.01
Preferred stock, shares authorized (in shares)	1,000,000	1,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, shares authorized (in shares)	200,000,000	200,000,000
Common stock, shares issued (in shares)	92,733,448	92,906,049
Common stock, shares outstanding (in shares)	92,733,448	92,906,049

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Oil and gas production revenues	$94,275	$68,499	$64,615
Other	56	74	7
Total revenue	94,331	68,573	64,622
Operating costs and expenses:	'	'	'
Lease operating	25,361	24,806	21,581
Production taxes	8,510	6,613	5,766
Depreciation, depletion, and amortization	26,632	23,016	16,194
Impairment	6,025	19,774	0
General and administrative (including stock-based compensation of $1,987, $2,091 and $2,114, respectively)	12,876	10,712	9,433
Operating expenses	79,404	84,921	52,974
Operating income (loss)	14,927	-16,348	11,648
Other (income) expense:	'	'	'
Interest income	-3	-4	-7
Interest expense	4,580	5,520	4,898
Amortization of deferred financing fees	1,367	937	1,762
Gain on sale of properties	-33,377	0	0
Loss on derivative contracts - realized	5,035	459	676
Gain on derivative contracts - unrealized	-2,561	-2,669	-7,476
Earnings from equity method investment	0	-2,207	-2,187
Other	539	97	316
Total other (income) expense	-24,420	2,133	-2,018
Income (loss) before income tax	39,347	-18,481	13,666
Income tax benefit (expense)	-700	-310	77
Net income (loss)	$38,647	($18,791)	$13,743
Net income (loss) - per common share - basic (in dollars per share)	$0.42	($0.20)	$0.15
Net income (loss) - per common share - diluted (in dollars per share)	$0.41	($0.20)	$0.15

CONSOLIDATED_STATEMENTS_OF_OPE1

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating costs and expenses:	'	'	'
Stock-based compensation	$2,114	$2,091	$1,987

CONSOLIDATED_STATEMENTS_OF_OTH

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]	'	'	'
Consolidated net income (loss)	$38,647	($18,791)	$13,743
Other comprehensive income (loss):	'	'	'
Change in unrealized value of investments	-79	-25	-76
Foreign currency translation adjustment	-559	343	-456
Other comprehensive income (loss)	-638	318	-532
Comprehensive income (loss)	$38,009	($18,473)	$13,211

CONSOLIDATED_STATEMENTS_OF_STO

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) (USD $)	Total	Common Stock [Member]	Additional Paid in Capital [Member]	Accumulated Deficit [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Balance at Dec. 31, 2010	($14,976,000)	$764,000	$184,223,000	($200,208,000)	$245,000
Balance (in shares) at Dec. 31, 2010	'	76,427,561	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Net income (loss)	13,743,000	0	0	13,743,000	0
Change in unrealized gain (loss) on fair value of investments	-76,000	0	0	0	-76,000
Foreign currency translation adjustment	-456,000	0	0	0	-456,000
Stock-based compensation	1,987,000	0	1,987,000	0	0
Shares issued for compensation	62,346,000	151,000	62,195,000	0	0
Shares issued for compensation (in shares)	'	15,075,502	'	'	'
Stock options exercised	83,000	4,000	79,000	0	0
Stock options exercised (in shares)	'	371,632	'	'	'
Restricted stock issued, net of cancellations	0	4,000	-4,000	0	0
Restricted stock issued, net of cancellations (in shares)	'	386,362	'	'	'
Balance at Dec. 31, 2011	62,651,000	923,000	248,480,000	-186,465,000	-287,000
Balance (in shares) at Dec. 31, 2011	'	92,261,057	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Net income (loss)	-18,791,000	0	0	'	0
Change in unrealized gain (loss) on fair value of investments	-25,000	0	0	0	-25,000
Foreign currency translation adjustment	343,000	0	0	0	343,000
Stock-based compensation	2,091,000	0	2,091,000	0	0
Stock options exercised	431,000	4,000	427,000	0	0
Stock options exercised (in shares)	'	390,957	'	'	'
Restricted stock issued, net of cancellations	0	0	0	0	0
Restricted stock issued, net of cancellations (in shares)	'	81,434	'	'	'
Balance at Dec. 31, 2012	46,700,000	927,000	250,998,000	-205,256,000	31,000
Balance (in shares) at Dec. 31, 2012	92,906,049	92,733,448	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Net income (loss)	38,647,000	0	0	'	0
Change in unrealized gain (loss) on fair value of investments	-79,000	0	0	0	-79,000
Foreign currency translation adjustment	-559,000	0	0	0	-559,000
Stock-based compensation	2,114,000	0	2,114,000	0	0
Stock options exercised	83,000	2,000	81,000	0	0
Stock options exercised (in shares)	'	129,686	'	'	'
Restricted stock issued, net of cancellations	0	0	0	0	0
Restricted stock issued, net of cancellations (in shares)	'	42,915	'	'	'
Balance at Dec. 31, 2013	$86,906,000	$929,000	$253,193,000	($166,609,000)	($607,000)
Balance (in shares) at Dec. 31, 2013	92,733,448	92,906,049	'	'	'

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
Operating Activities	'	'	'
Net income (loss)	$38,647	($18,791)	$13,743
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Earnings from equity method investment	0	-2,207	-2,187
Gain on sale of properties	-33,377	0	0
Change in derivative fair value	-2,403	-4,088	-7,680
Monetization of derivative contracts	0	12,364	0
Depreciation, depletion, and amortization	26,632	23,016	16,194
Impairment	6,025	19,774	0
Accretion of future site restoration	638	474	452
Amortization of deferred financing fees	1,367	937	1,762
Stock-based compensation	2,114	2,091	1,987
Changes in operating assets and liabilities:	'	'	'
Accounts receivable	-13,215	-7,506	-182
Other assets and liabilities	-176	250	-17
Accounts payable	27,294	22,024	756
Accrued expenses	-1,892	3,037	-333
Net cash provided by operating activities	51,654	51,375	24,495
Investing Activities	'	'	'
Capital expenditures, including purchases and development of properties	-95,043	-68,552	-79,012
Proceeds from the sale of oil and gas properties	127,529	21,549	8,457
Net cash (used in) provided by investing activities	32,486	-47,003	-70,555
Financing Activities	'	'	'
Proceeds from exercise of stock options and warrants	83	431	83
Proceeds from issuance of common stock, net of offering costs	0	0	62,346
Proceeds from long-term borrowings	42,000	30,500	50,500
Payments on long-term borrowings	-122,826	-32,181	-65,153
Deferred financing fees	-110	-844	-1,758
Other	-161	-217	-52
Net cash provided by (used in) financing activities	-81,014	-2,311	45,966
Effect of exchange rate changes on cash	18	0	-5
(Decrease) increase in cash	3,144	2,061	-99
Cash at beginning of year	2,061	0	99
Cash at end of year	5,205	2,061	0
Supplemental disclosure of cash flow information:	'	'	'
Interest paid	3,986	5,180	4,514
Income taxes paid	391	0	-77
Non-Cash Investing Activities:	'	'	'
Asset retirement obligation cost and liabilities	138	2,588	-8
Non-cash transfer of investment in joint venture	0	-28,531	0
Asset retirement obligations associated with property acquisitions and dispositions	($1,890)	$324	$306

Organization_and_Significant_A

Organization and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Organization and Significant Accounting Policies	'
	Organization and Significant Accounting Policies
	Nature of Operations
	We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States and Canada.  Our oil and gas assets are located in three operating regions in the United States, the Rocky Mountain, Permian Basin and onshore Gulf Coast, and in the province of Alberta, Canada.
	The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”) and its wholly-owned foreign subsidiary, Canadian Abraxas Petroleum, ULC (“Canadian Abraxas”). The term “Partnership” refers only to Abraxas Energy Partners, L.P.
	Canadian Abraxas’ assets and liabilities are translated to U.S. dollars at period-end exchange rates.  Income and expense items are translated at average rates of exchange prevailing during the period.  Translation adjustments are accumulated as a separate component of stockholders’ equity.
	Rig Accounting
	In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates holds an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced.
	Use of Estimates
	The preparation of consolidated 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 disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
	Concentration of Credit Risk
	Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts.  Accounts receivable are generally from companies with significant oil and gas marketing activities.  The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties.
	The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality.
	Cash and Equivalents
	Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.
	Accounts Receivable
	Accounts receivable are reported net of an allowance for doubtful accounts of approximately $105,000 and $407,000 at December 31, 2012 and 2013, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.
	Oil and Gas Properties
	The Company follows the full cost method of accounting for oil and gas properties.  Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. As of December 31, 2011, our net capitalized costs of oil and gas properties in the United States and Canada did not exceed the present value of our estimated proved reserves. As of December 31, 2012, net capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved reserves; however, the net capitalized costs of oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $19.8 million resulting in a write down for the year ended December 31, 2012. Write downs of $1.3 million, $11.8 million and $6.7 million were taken in the second, third and fourth quarters of 2012, respectively. As of December 31, 2013, net capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved reserves; however, the net capitalized costs of oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $6.0 million resulting in a write down for the year ended December 31, 2013. There were write downs in the second, third and fourth quarters of 2013 of $2.0 million; $0.1 million and $3.9 million, respectively.
	Other Property and Equipment
	Other property and equipment are recorded on the basis of cost.  Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method.  Major renewals and improvements are recorded as additions to the property and equipment accounts.  Repairs that do not improve or extend the useful lives of assets are expensed.
	Estimates of Proved Oil and Gas Reserves
	Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:
	•the quality and quantity of available data;
	•the interpretation of that data;
	•the accuracy of various mandated economic assumptions; and
	•the judgment of the persons preparing the estimate.
	Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the Engineering and Operations departments of Abraxas. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may cause material revisions to the estimate.
	In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the average 12 month first-day-of-month pricing for the years ended December 31, 2012 and 2013, and costs as of December 31, 2012 and 2013. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.
	The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields.
	Derivative Instruments and Hedging Activities
	The Company enters into agreements to hedge the risk of future oil and gas price fluctuations.  Such agreements are in the form of fixed price swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. The Company does not enter into speculative hedges.
	The Company accounts for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for hedge accounting rules as prescribed by Accounting Standards Codification (“ASC”) 815. Accordingly, we do not account for our derivative instruments as cash flow hedges for financial reporting purposes and instead record their fair value on the balance sheet with adjustments to the carrying value of the instruments being recognized as a gain or loss in the current period.
	Fair Value of Financial Instruments
	The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value.  The carrying value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments.  For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.
	Share-Based Payments
	The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors.  Options granted are valued at the date of grant and expense is recognized over the vesting period. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the years ended December 31, 2011, 2012 and 2013, stock-based compensation was approximately $2.0 million, $2.1 million and $2.1 million, respectively. For additional information regarding share-based payments, refer to Note 6, “Stock-Based Compensation, Option Plans and Warrants.”
	Restoration, Removal and Environmental Liabilities
	The Company is subject to extensive Federal, provincial, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
	Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.
	The Company accounts for asset retirement obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements.
	The following table summarizes the Company’s asset retirement obligations during the two years ended December 31:
		2012			2013
	Beginning asset retirement obligation	$	8,412		$	11,381
	New wells placed on production and other	330			222
	Deletions related to property disposals and plugging costs	(423		)	(2,491		)
	Accretion expense	474			638
	Revisions	2,588			138
	Ending asset retirement obligation	$	11,381		$	9,888
	Revenue Recognition and Major Purchasers
	The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. The Company utilizes the sales method to account for gas production imbalances.  Under this method, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2012 and 2013.
	During 2011, two purchasers accounted for 28% of oil and gas revenues. During 2012, three purchasers accounted for 39% of oil and gas revenues. During 2013, two customers accounted for 49% of our oil and gas revenues.
	Deferred Financing Fees
	Deferred financing fees are being amortized on the effective yield basis over the term of the related debt arrangements.
	Income Taxes
	The Company records deferred income taxes using the asset and liability method.  Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10. Therefore, we have established a valuation allowance of $75.6 million for deferred tax assets at December 31, 2013.
	Accounting for Uncertainty in Income Taxes
	ASC 740 provides guidance on accounting for uncertainty in income taxes.  ASC 740 is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC 740 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.
	Under ASC 740, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.
	Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense.
	Other Comprehensive Income (Loss)
	ASC 220 requires disclosure of comprehensive income (loss), which includes reported net income (loss) as adjusted for other comprehensive income (loss). Other Comprehensive income (loss) for the Company is the change in the unrealized value of investments and foreign currency translation adjustments.

Joint_Venture

Joint Venture	12 Months Ended
	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]	'
Joint Venture	'
	Joint Venture
	On August 18, 2010, Abraxas Petroleum and its wholly-owned subsidiary, Abraxas Operating, LLC, contributed 8,333 net acres in the Eagle Ford Shale play to Blue Eagle Energy, LLC (“Blue Eagle”) and received a $25.0 million equity interest in Blue Eagle pursuant to the terms of the Subscription and Contribution Agreement among Abraxas Petroleum, Abraxas Operating, Blue Eagle and Rock Oil Company, LLC (“Rock Oil”) formerly known as Blue Stone Oil & Gas, LLC. Simultaneously, Rock Oil contributed $25.0 million in cash to Blue Eagle for a $25.0 million equity interest. Blue Eagle was dissolved effective August 31, 2012.
	Through August 31, 2012 we accounted for the joint venture under the equity method of accounting in accordance with ASC 323. Under this method, Abraxas’ share of net income (loss) from the joint venture is reflected as an increase (decrease) in its investment account in “Investment in joint venture” and was also recorded as equity investment income (loss) in “Earnings from equity method investment.” For the years ended December 31, 2011 and 2012 we reported income of $2.2 million and $2.2 million, respectively, related to Blue Eagle.
	The following is condensed financial data from Blue Eagle’s August 31, 2012 (date of dissolution) and December 31, 2011 financial statements:
		As of
		August 31,
		2012
	Balance Sheets:
	Assets:
	Current assets	$	7,921
	Oil and gas properties	75,741
	Other assets	30
	Total assets	$	83,692
	Liabilities and Members’ Capital:
	Current liabilities	$	1,474
	Other liabilities	48
	Members’ capital	82,170
	Total liabilities and members’ capital	$	83,692
		Year Ended			Year Ended
		December 31,			December 31,
	Statement of Operations:	2011			2012 (1)
		(In thousands)
	Revenue	$	12,579		$	12,106
	Operating expenses	7,138			7,144
	Other income	(11		)	(4		)
	Net income	$	5,452		$	4,966
	(1) Through August 31, 2012

Divestiture_of_NonCore_Propert

Divestiture of Non-Core Properties	12 Months Ended
	Dec. 31, 2013
Divestiture of Non Core Properties [Abstract]	'
Divestiture of Non-Core Properties	'
	Divestiture of Properties
	Beginning in the third quarter of 2012 and continuing throughout 2013, the Company's business plan has been to divest various properties considered non core, and primarily non-operated to focus on its core basins in the Eagle Ford, Bakken, Powder River Basin and Permian Basin.
	In the third quarter of 2012 we sold certain non-core assets for combined net proceeds of approximately $21.5 million. Properties sold included certain properties received upon the dissolution of the Blue Eagle joint venture. During 2013 the Company sold various non-operated properties through the auction process. Total proceeds from these auctions were approximately $6.6 million. In addition to the auctions, the Company completed three other significant dispositions. The Company monetized the Bakken and Three Forks rights on the Company’s Fairview Prospect in Richland County, Montana and McKenzie County, North Dakota for $10.6 million. The sale consisted of approximately 2,563 net acres and did not have any associated production. In August 2013 the Company's non-operated properties in the Bakken were monetized for net proceeds of $38.3 million. In December 2013, the Company closed on the divestiture of its non-operated position in the Wycross area of the Eagle Ford for net proceeds of $71.4 million. Other property sales during the year netted $0.6 million.
	The net proceeds were used to repay outstanding indebtedness under our credit facility, for capital expenditures and general corporate purposes. Proceeds from these sales, except for the Wycross sale, were credited to the full cost pool as these sales were not significant under full cost accounting rules. Due to the magnitude of the Wycross sale and its impact on the relationship of capitalized costs and reserves, a gain of $33.4 million was recognized on this sale.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	The following is a description of the Company’s debt as of December 31, 2012 and 2013, respectively:
			December 31,			December 31,
			2012			2013
			(In thousands)
	Senior secured credit facility		$	113,000		$	33,000
	Rig loan agreement		7,000			6,378
	Real estate lien note		4,758			4,554
			124,758			43,932
	Less current maturities		(657		)	(2,142		)
			$	124,101		$	41,790
	Maturities of long-term debt are as follows:
	Year ending December 31, (In thousands)
	2014	$	2,142
	2015	35,235
	2016	2,332
	2017	608
	2018	262
	Thereafter	3,353
		$	43,932
	Credit Facility
	We have a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility.  As of December 31, 2013, $33.0 million was outstanding under the credit facility.
	The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At December 31, 2013, we had a borrowing base of $130.0 million. This amount will remain in effect until the next redetermination of the borrowing base which is scheduled to be completed in April 2014. The borrowing base is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations.  The borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base can never exceed the $300.0 million maximum commitment amount.  Outstanding amounts under the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 1.25%—2.25%, depending on the utilization of the borrowing base, or, if we elect LIBOR plus 2.25%—3.25%, depending on the utilization of the borrowing base. At December 31, 2013, the interest rate on the credit facility was 2.67% based on 1-month LIBOR borrowings and level of utilization.
	Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2015. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.
	Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets, other than Raven Drilling.
	Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements.  We are required to maintain a current ratio, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00.  We are also required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 4.00 to 1.00.The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities.  For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20.  The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date.  For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the office building, Raven Drilling’s  rig loan and obligations with respect to surety bonds and derivative contracts.
	At December 31, 2013 we were in compliance with all of our debt covenants. As of December 31, 2013, the interest coverage ratio was 11.20 to 1.00, the total debt to EBITDAX ratio was 0.76 to 1.00, and our current ratio was 1.75 to 1.00.
	The credit facility contains a number of covenants that, among other things, restrict our ability to:
	•	incur or guarantee additional indebtedness;
	•	transfer or sell assets;
	•	create liens on assets;
	•	engage in transactions with affiliates other than on an “arm’s length” basis;
	•	make any change in the principal nature of our business; and
	•	permit a change of control.
	The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.
	Rig Loan Agreement
	On September 19, 2011, Raven Drilling entered into a rig loan agreement with RBS Asset Finance, Inc. to finance the costs of purchasing and refurbishing an Oilwell 2000 HP diesel electric drilling rig (the “Collateral”). The rig loan agreement provided for interim borrowings payable to Raven Drilling until the final amount of the loan was determined.
	On February 14, 2012, Raven Drilling finalized the note with respect to the rig loan agreement.  The principal amount of the note is $7.0 million and bears interest at 4.26%.  Interest only was due for the first 18-months of the note and thereafter, the note will amortize in full over the remaining life of the note.  Interest and principal, when required, is payable monthly.  Subject to earlier prepayment provisions and events of default, the stated maturity date of the note is February 14, 2017. As of December 31, 2012 and 2013, $7.0 million and $6.4 million, respectively, were outstanding under the rig loan agreement.
	The Company has guaranteed Raven Drilling’s obligations under the rig loan agreement and associated note.  Obligations under the rig loan agreement are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in the Collateral.
	Real Estate Lien Note
	On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a building to serve as its corporate headquarters.  The note was modified on April 4, 2013, reducing the interest to a fixed rate of 4.0%, effective March 13, 2013 and was payable in monthly installments of principal and interest of $33,763 based on a twenty year amortization. This note was modified on July 20, 2013 to extend the maturity date to July 20, 2023. The note will bear interest for five years at a fixed rate of 4.25% and is payable in monthly installments of $34,354. Beginning August 20, 2018, the interest rate will adjust to the current bank prime rate plus 1.00% with a maximum rate of 7.25%. The note is secured by a first lien deed of trust on the property and improvements. As of December 31, 2012 and 2013, $4.8 million and $4.6 million, respectively, were outstanding on the note.

Property_and_Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property and Equipment	'
	Property and Equipment
	The major components of property and equipment, at cost, are as follows:
		Estimated Useful Life	December 31,
			2012		2013
		Years	(In thousands)
	Oil and gas properties	—	$	565,406	$	564,755
	Equipment and other	Mar-39	19,052		17,237
	Drilling rig	15	18,781		21,722
			$	603,239	$	603,714

Stockbased_Compensation_Option

Stock-based Compensation, Option Plans and Warrants	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock-based Compensation, Option Plans and Warrants	'
	Stock-Based Compensation and Option Plans
	Stock Options
	The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. The fair value for these options was estimated at the date of grant using the following weighted average assumptions for 2011, 2012 and 2013:
		2011				2012				2013
	Weighted average value per option granted during the period	$	3.11			$	2.17			$	1.73
	Assumptions: (1)(2)
	Expected dividend yield	—		%		—		%		—		%
	Volatility	80		%		81.4		%		81.2		%
	Risk free interest rate	2.21		%		1.19		%		1.24		%
	Expected life (years)	6.4				6.7				6.5
	Fair value of options granted (in thousands)	$	2,506			$	1,324			$	1,444
	(1)    The estimated future forfeiture rate is based on the Company’s historical forfeiture rate.
	(2)    The Company does not pay dividends on its common stock.
	The Company grants options to its officers, directors, and other employees under various stock option and incentive plans.
	The Company’s 2005 Employee Long-Term Equity Incentive Plan has authorized the grant of up to 5.2 million awards to management and employees, including options. Options have a term not to exceed 10 years. Options issued under this plan vest according to a vesting schedule as determined by the compensation committee of the Company’s board of directors. Vesting may occur upon (1) the attainment of one or more performance goals or targets established by the committee, (2) the optionee’s continued employment or service for a specified period of time, (3) the occurrence of any event or the satisfaction of any other condition specified by the committee, or (4) a combination of any of the foregoing.
	The following table is a summary of the Company’s stock option activity for the three years ended December 31:
		Options			Weighted average				Weighted
		(000s)			exercise price				average		Intrinsic
									remaining life		value
											per share
	Options outstanding December 31, 2010	4,820			$	2.23
	Granted	807			4.37
	Exercised	(530	)		1.54
	Forfeited/Expired	(341	)		3.01
	Options outstanding December 31, 2011	4,756			$	2.61
	Granted	610			3.01
	Exercised	(391	)		1.11
	Forfeited/Expired	(214	)		2.8
	Options outstanding December 31, 2012	4,761			$	2.77
	Granted	836			$	2.43
	Exercised	(166	)		1.18
	Forfeited/Expired	(31	)		2.58
	Options outstanding December 31, 2013	5,400			$	2.77			6.2		$	1.98
	Exercisable at end of year	3,828			$	1.93			5.3		$	1.93
	Other information pertaining to the Company’s stock option activity for the three years ended December 31:
		2011				2012				2013
	Weighted average grant date fair value of stock options granted  (per share)	$	3.11			$	2.17			$	1.73
	Total fair value of options vested (000’s)	$	1,230			$	1,497			$	1,670
	Total intrinsic value of options exercised (000’s)	$	1,584			$	414			$	275
	As of December 31, 2013, the total compensation cost related to non-vested awards not yet recognized was approximately $2.2 million, which will be recognized in 2014 through 2017. For the years ended December 31, 2011, 2012 and 2013, we recognized $1.5 million, $1.6 million and $1.7 million respectively, in stock-based compensation expense relating to options.
	The following table represents the range of stock option prices and the weighted average remaining life of outstanding options as of December 31:
		Options outstanding									Exercisable
					Weighted		Weighted						Weighted	Weighted
		Number			average		average				Number		average	average
		outstanding			remaining		exercise				exercisable		remaining	exercise
					life		price						life	price
	0.68 – 0.99	627,450			5.21		$	0.99			627,450		5.21	$	0.99
	1.00 – 1.99	1,114,672			6.28		$	1.75			964,672		5.91	$	1.71
	2.00 – 2.99	1,670,025			7.66		$	2.32			816,925		6.57	$	2.31
	3.00 – 3.99	745,563			6.73		$	3.64			399,427		5.49	$	3.62
	4.00 – 4.99	1,168,500			4.47		$	4.58			945,250		3.83	$	4.55
	5.00 – 6.05	74,000			2.15		$	6.05			74,000		2.15	$	6.05
		5,400,210									3,827,724
	Restricted Stock Awards
	Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. Compensation expense is recorded over the applicable restricted stock vesting periods. As of December 31, 2013, the total compensation cost related to non-vested awards not yet recognized was approximately $0.8 million, which will be recognized in 2014 through 2017. For the years ended December 31, 2011, 2012 and 2013, we recognized $0.5 million, $0.5 million and $0.4 million, respectively, in stock-based compensation expense related to restricted stock awards.
	The following table is a summary of the Company’s restricted stock activity for the three years ended December 31:
		Number			Weighted
		of			average
		Shares			grant date
					fair value
	Unvested December 31, 2010	400,295			$	2.02
	Granted	408,676			3.67
	Vested/Released	(156,890	)		2.24
Forfeited	(22,310	)		2.27
Unvested December 31, 2011	629,771			$	3.03
Granted	89,860			2.12
Vested/Released	(229,172	)		2.57
Forfeited	(8,434	)		2.42
Unvested December 31, 2012	482,025			$	3.09
Granted	48,222			2.69
Vested/Released	(169,700	)		2.66
Forfeited	(5,307	)		3.08
Unvested December 31, 2013	355,240			$	3.24
Director Stock Awards
Shares Reserved and Awards.  The 2005 Directors Plan (as amended) reserves 1.5 million shares of Abraxas common stock, subject to adjustment following certain events. The 2005 Directors Plan provides that each year, at the first regular meeting of the board of directors immediately following Abraxas’ annual stockholder’s meeting, each non-employee director shall be granted or issued awards of 12,000 shares of Abraxas common stock, for participation in board and committee meetings during the previous calendar year.  The maximum annual award for any one person is 100,000 shares of Abraxas common stock or options for common stock.  If options, as opposed to shares, are awarded, the exercise price shall be no less than 100% of the fair market value on the date of the award while the option terms and vesting schedules are at the discretion of the committee.  In addition to the 12,000 shares or options, between April 2010 and April 2011, directors were compensated for their annual retainer fee of $26,000 in cash, which increased to $27,500 in April 2011 and to $40,000 in April 2012. The retainer fee remained at $40,000 during 2013.
At December 31, 2013, the Company had approximately 9.0 million shares reserved for future issuance for conversion of its stock options, warrants, and incentive plans for the Company’s directors, employees and consultants.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	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 purposes.  Significant components of the Company’s deferred tax liabilities and assets are as follows:
		Years Ended December 31,
		2011			2012			2013
		(In thousands)
	Deferred tax liabilities:
	Marketable securities	$	36		$	28		$	—
	Canada full cost pool	377			—			—
	Investment in Blue Eagle	7,527			—			—
	Hedge contracts	345			—			—
	Other	—			—			3,152
	Total deferred tax liabilities	8,285			28			3,152
	Deferred tax assets:
	U.S. full cost pool	29,976			13,837			11,725
	Canada full cost pool	—			3,720			4,081
	Depletion carryforward	4,842			4,930			4,743
	U.S. net operating loss  carryforward	52,564			59,362			49,667
	Canada net operating loss carryforward	2,151			4,196			5,736
	Alternative minimum tax credit	422			422			1,369
	Hedge contracts	—			2,231			1,397
	Other	1,811			1,042			—
	Total deferred tax assets	91,766			89,740			78,718
	Valuation allowance for deferred tax assets	(83,481		)	(89,712		)	(75,566		)
	Net deferred tax assets	8,285			28			3,152
	Net deferred tax	$	—		$	—		$	—
	Significant components of the provision (benefit) for income taxes are as follows:
		Years ended December 31,
		2011			2012			2013
		(In thousands)
	Current:
	Federal	$	(77	)	$	310		$	632
	State	—			—			68
	Foreign	—			—			—
		$	(77	)	$	310		$	700
	Deferred:
	Federal	$	—		$	—		$	—
	Foreign	—			—			—
		$	—		$	—		$	—
	At December 31, 2013, the Company had, subject to the limitation discussed below, $141.9 million of net operating loss carryforwards for U.S. tax purposes, and $20.5 million of net operating loss carryforwards for Canadian tax purposes.  The U.S. loss carryforward will expire in varying amounts through 2033 and the Canadian loss carryforward will expire in 2033, if not utilized.
	The use of our net operating loss carryforwards will be limited if there is an "ownership change" in our common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of December 31, 2013, we have not had an ownership change as defined by Section 382. In addition to any Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10. Therefore, the Company has established a valuation allowance of $83.5 million at December 31, 2011, $89.7 million at December 31, 2012 and $75.6 million at December 31, 2013.
	The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:
		Years ended December 31,
		2011			2012			2013
		(In thousands)
	Tax (expense) benefit at U.S. statutory rates (35%)	$	(4,809	)	$	6,468		$	(13,771	)
	(Increase) decrease in deferred tax asset valuation allowance	5,408			(6,231		)	14,146
	Rate differential for non U.S. income	(46		)	(1,533		)	(574		)
	State income taxes	—			—			(47		)
	Accrual of prior year federal taxes (2009)	—			(310		)	(81		)
	Permanent differences	(533		)	(732		)	(743		)
	Increase in asset  for partnership distribution	—			1,945			—
	Other	57			83			370
		$	77		$	(310	)	$	(700	)
	During 2013, the Company reduced deferred tax assets by $11.0 million related to the full cost pool assets and the net operating loss carryforward.  The deferred tax assets were fully offset by a valuation allowance which was reduced at the same time. There were no deferred income tax expense or benefit due to losses and/or loss carryforwards and valuation allowances which have been recorded against such benefits.
	The Company accounts for uncertain tax positions under provisions ASC 740-10. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2013 and 2012, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2003 through 2013 remain open to examination by the tax jurisdictions to which the Company is subject. The Company and Abraxas Energy Partners, L.P., which was merged into a wholly owned subsidiary of Abraxas, have undergone audits of their 2009 Federal income tax returns. The audit of the Federal income tax return of Abraxas Energy Partners, L.P. was completed with no changes. The audit of Abraxas Petroleum Corporation resulted in a notice of a proposed adjustment of $619,000. For the year ended December 31, 2012, the Company accrued $310,000 in income tax expense related to the audit of its 2009 Federal tax return. This amount was determined by an analysis of what the amount that is greater than 50% likely to be paid upon final settlement. On July 23, 2013, we settled the assessment for $391,000 resulting in $81,000 being recognized as expense in 2013.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Operating Leases
	The Company leased office space in Calgary, Alberta.  During 2011, 2012 and 2013, rent expense of $121,500 ;$112,276 and $107,619 , respectively, was incurred related to this lease. In July 2011, the Company leased office space in Dickinson, North Dakota. During 2011, 2012 and 2013, rent expense of $9,250; $23,800, and $26,073, respectively was incurred related to this lease. This lease expires on August 31, 2014. The Company leases office space in Lusk, Wyoming. For each of the years 2011, 2012 and 2013, rent expense of $9,000 was incurred on this lease. The lease expires on December 31, 2016.
	Litigation and Contingencies
	From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business.  At December 31, 2013, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the Company.

Earnings_per_Share

Earnings per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings per Share	'
	Earnings per Share
	The following table sets forth the computation of basic and diluted earnings per share:
		Years ended December 31:
		2011		2012			2013
		(In thousands, except per share data)
	Numerator:
	Net income (loss)	$	13,743	$	(18,791	)	$	38,647
	Denominator:
	Denominator for basic earnings per share – weighted-average common shares outstanding	90,151		91,914			92,451
	Effect of dilutive securities:	2,093		—			1,087
	Stock options, restricted shares and warrants
	Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options, restricted shares and warrants	92,244		91,914			93,538
	Net income (loss) per common share  – basic	$	0.15	$	(0.20	)	$	0.42
	Net income (loss) per common share – diluted	$	0.15	$	(0.20	)	$	0.41
	Basic earnings per share, excluding any dilutive effects of stock options, warrants and unvested restricted stock, is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities. For the year ended December 31, 2012, 1,349 potential shares relating to stock options and unvested restricted shares were excluded from the calculation of diluted income (loss) per share since their inclusion would have been anti-dilutive due to the loss incurred in the period. None of the dilutive shares were excluded for the years ended December 31, 2011 and 2013.

Quarterly_Results_of_Operation

Quarterly Results of Operations (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Results of Operations (Unaudited)	'
	Quarterly Results of Operations (Unaudited)
	Selected results of operations for each of the fiscal quarters during the years ended December 31, 2012 and 2013 are as follows:
		1st		2nd			3rd			4th
		Quarter		Quarter			Quarter			Quarter
		(In thousands, except per share data)
	Year Ended December 31, 2012
	Net revenue	$	16,396	$	15,938		$	17,170		$	19,069
	Operating income	$	2,224	$	(23	)	$	(11,359	)	$	(7,190	)
	Net (loss) income	$	817	$	10,903		$	(18,644	)	$	(11,867	)
	Net (loss) income per common share – basic	$	0.01	$	0.12		$	(0.20	)	$	(0.13	)
	Net (loss) income per common share – diluted	$	0.01	$	0.12		$	(0.20	)	$	(0.13	)
	Year Ended December 31, 2013
	Net revenue	$	21,196	$	21,494		$	29,095		$	22,546
	Operating income (loss)	$	3,768	$	2,867		$	11,161		$	(2,869	)
	Net income (loss) income	$	595	$	7,866		$	3,190		$	26,996
	Net income (loss) per common share – basic	$	0.01	$	0.09		$	0.03		$	0.29
	Net income (loss) per common share – diluted	$	0.01	$	0.08		$	0.03		$	0.29

Benefit_Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Benefit Plans	'
	Benefit Plans
	The Company has a defined contribution plan (401(k) plan) covering all eligible employees. In 2011, 2012 and 2013, in accordance with the safe harbor provisions of the plan, the Company contributed $226,377, $267,289 and $284,865, respectively, to the plan. The Company adopted the safe harbor provisions for its 401(k) plan which requires us to contribute a fixed match to each participating employee’s contribution to the plan. The fixed match is set at the rate of dollar for dollar on the first 1% of eligible pay contributed, then 50 cents on the dollar for each additional percentage point of eligible pay contributed, up to 5%. Employee’s eligible pay with respect to calculating the fixed match is limited by IRS regulations. In addition, the Board of Directors, at its sole discretion, may authorize the Company to make additional contributions to each participating employee’s plan. The employee contribution limit for 2011 was $16,500 for employees under the age of 50 and $22,000 for employees 50 years of age or older and  2012  was $17,000 for employees under the age of 50 and $22,500 for employees 50 years of age or older. For 2013 the employee contribution limit was $17,500 for employees under the age of 50 and $23,000 for employees 50 years of age or older.

Business_Segments

Business Segments	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Business Segments	'
	Business Segments
	The Company has operations in only one industry segment, the oil and gas exploration and production industry; however, beginning in 2010, the Company was organizationally structured along geographic operating segments or regions. The Company has reportable operations in the United States and Canada.
	In 2011, three customers accounted for approximately 28% of our consolidated oil and gas revenue. Two customers accounted for approximately 26% of United States revenue and one customer accounted for 100% of revenue in Canada. In 2012, four customers accounted for approximately 31% of our consolidated oil and  gas revenue. Three customers accounted for approximately 28% of United States revenue and one customer accounted for 100% of revenue in Canada. In 2013, three customers accounted for approximately 50% of our consolidated oil and  gas revenue. Two customers accounted for approximately 49% of United States revenue and one customer accounted for 100% of revenue in Canada.
	The following tables provide the Company’s geographic operating segment data as of and for the year ended December 31, 2011, 2012 and 2013:
		Year Ended December 31, 2011
		U.S.		Canada			Corporate			Total
		(In thousands)
	Revenues:
	Oil and gas production	$	63,105	$	1,510		$	—		$	64,615
	Other	—		—			7			7
		63,105		1,510			7			64,622
	Costs and expenses:
	Lease operating	20,788		793			—			21,581
	Production taxes	5,764		2			—			5,766
	Depreciation, depletion and amortization	15,236		709			249			16,194
	Impairment	—		—			—			—
	General and administrative	1,698		654			7,081			9,433
	Net interest	448		4			4,439			4,891
	Amortization of deferred financing fees	—		—			1,762			1,762
	Loss on derivative contracts - realized	—		—			676			676
	Gain on derivative contracts - unrealized	—		—			(7,476		)	(7,476		)
	Earnings from equity method investment	—		—			(2,187		)	(2,187		)
	Other	—		—			316			316
	Income tax	—		—			(77		)	(77		)
	Income (loss)	$	19,171	$	(652	)	$	(4,776	)	$	13,743
		Year Ended December 31, 2012
		U.S.		Canada			Corporate			Total
		(In thousands)
	Revenues:
	Oil and gas production	$	65,590	$	2,909		$	—		$	68,499
	Other	—		—			74			74
		65,590		2,909			74			68,573
	Costs and expenses:
	Lease operating	22,578		2,228			—			24,806
	Production taxes	6,588		25			—			6,613
	Depreciation, depletion and amortization	20,704		2,063			249			23,016
	Impairment	—		19,774			—			19,774
	General and administrative	1,980		699			8,033			10,712
	Net interest	457		17			5,042			5,516
	Amortization of deferred financing fees	—		—			937			937
	Loss on derivative contracts - realized	—		—			459			459
	Gain on derivative contracts - unrealized	—		—			(2,669		)	(2,669		)
	Earnings from equity method investment	—		—			(2,207		)	(2,207		)
	Income tax expense	—		—			310			310
	Other	—		—			97			97
	Income (loss)	$	13,283	$	(21,897	)	$	(10,177	)	$	(18,791	)
		Year Ended December 31, 2013
		U.S.		Canada			Corporate			Total
		(In thousands)
	Revenues:
	Oil and gas production	$	92,268	$	2,007		$	—		$	94,275
	Other	—		—			56			56
		92,268		2,007			56			94,331
	Costs and expenses:
	Lease operating	23,205		2,156			—			25,361
	Production taxes	8,437		73			—			8,510
	Depreciation, depletion and amortization	25,338		1,045			249			26,632
	Impairment	—		6,025			—			6,025
	General and administrative	2,471		879			9,526			12,876
	Net interest	615		23			3,939			4,577
	Amortization of deferred financing fees	—		—			1,367			1,367
	Gain on sale of properties	—		—			(33,377		)	(33,377		)
	Loss on derivative contracts - realized	—		—			5,035			5,035
Gain on derivative contracts - unrealized	—		—			(2,561		)	(2,561		)
Income tax	—		—			700			700
Other	—		—			539			539
Income (loss)	$	32,202	$	(8,194	)	$	14,639		$	38,647
The following table provides the Company’s geographic asset data as of December 31, 2012 and December 31, 2013:
Segment Assets:	December 31,		December 31,
	2012		2013
	(In thousands)
United States	$	223,253	$	213,212
Canada	7,053		1,640
Corporate	10,301		8,798
	$	240,607	$	223,650

Hedging_Program_and_Derivative

Hedging Program and Derivatives	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Hedging Program and Derivatives	'
	Hedging Program and Derivatives
	The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  Our derivative contracts do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period.
	The following table sets forth the summary position of our derivative contracts as of December 31, 2013:
		Oil - WTI					Oil - Brent					Oil - LLS
	Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)			Daily Volume (Bbl)			Swap Price (per Bbl)		Daily Volume (Bbl)	Swap Price (per Bbl)
	2014	687		$	94.16		505			$	100.56	100	$	101.26
	2015	560		$	83.03		500			$	97.04	—	$	—
	2016	963		$	84.1		—			$	—	—	$	—
	2017	500		$	84.18		—			$	—	—	$	—
	Subsequent to December 31, 2013 we entered into the following derivative contracts:
		Natural Gas - NYMEX
	Contract Periods	Daily Volume (Mcf)		Swap Price (Per Mcf)
	2014	1,597		$	4.1
	2015	1,450		$	4.22
	The following table illustrates the impact of derivative contracts on the Company’s balance sheet:
	Fair Value of Derivative Instruments as of December 31, 2012
		Asset Derivatives				Liability Derivatives
	Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value			Balance Sheet Location		Fair Value
	Commodity price derivatives	Derivatives – current	$	41		Derivatives – current		$	3,462
	Commodity price derivatives	Derivatives – long-term	594			Derivatives – long-term		3,568
			$	635				$	7,030
	Fair Value of Derivative Instruments as of December 31, 2013
		Asset Derivatives				Liability Derivatives
	Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value			Balance Sheet Location		Fair Value
	Commodity price derivatives	Derivatives – current	$	85		Derivatives – current		$	2,728
	Commodity price derivatives	Derivatives – long-term	925			Derivatives – long-term		2,274
			$	1,010				$	5,002
	Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying Consolidated Statements of Operations.

Financial_Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Financial Instruments	'
	Financial Instruments
	The Company applies ASC 820-10  which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.
	Fair Value Hierarchy—ASC 820-10 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
	•	Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
	•	Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
	•	Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.
	A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and 2013, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):
			Quoted Prices		Significant
			in Active		Other
			Markets for		Observable		Significant		Balance as of
			Identical		Inputs		Unobservable		December 31,
			Assets		(Level 2)		Inputs (Level 3)		2012
			(Level 1)
	Assets:
	Investment in common stock		$	78	$	—	$	—	$	78
	NYMEX Fixed Price Derivative contracts		—		635		—		635
	Total Assets		$	78	$	635	$	—	$	713
	Liabilities:
	NYMEX Fixed Price Derivative contracts		$	—	$	7,030	$	—	$	7,030
	Total Liabilities		$	—	$	7,030	$	—	$	7,030
			Quoted Prices		Significant
			in Active		Other
			Markets for		Observable		Significant		Balance as of
			Identical		Inputs		Unobservable		December 31,
			Assets		(Level 2)		Inputs (Level 3)		2013
			(Level 1)
	Assets:
	NYMEX Fixed Price Derivative contracts		$	—	$	1,010	$	—	$	1,010
	Total Assets		$	—	$	1,010	$	—	$	1,010
	Liabilities:
	NYMEX Fixed Price Derivative contracts		$	—	$	5,002	$	—	$	5,002
	Total Liabilities		$	—	$	5,002	$	—	$	5,002
	The Company had an investment in Insignia Energy Ltd, the surviving entity in the merger with a former subsidiary, consisting of shares of common stock. The stock was actively traded on the Toronto Stock Exchange. This investment was valued at its quoted price as of December 31, 2012 in U.S. dollars. Accordingly, this investment is characterized as Level 1. On May 6, 2013, Insignia Energy Ltd, announced plans to privatize the company whereby all shareholders would receive C$1.35 per share. On July 19, 2013 Insignia announced that it had completed the plan. On August 12, 2013 the Company received $133,592 cash consideration for its shares.
	The Company’s derivative contracts consist of NYMEX-based fixed price commodity swaps. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, we enter the various inputs into a model and compare our results to the third party for reasonableness.
	Other Financial Instruments
	The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2.

Supplemental_Oil_and_Gas_Discl

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Supplemental Oil and Gas Disclosures (Unaudited)	'
	15.  Supplemental Oil and Gas Disclosures (Unaudited)
	The accompanying table presents information concerning the Company’s oil and gas producing activities as required by ASC 932-235, “Disclosures about Oil and Gas Producing Activities.”  Capitalized costs relating to oil and gas producing activities are as follows:
			Years Ended December 31
			2012											2013
			Total				U.S.				Canada			Total				U.S.				Canada
			(In thousands)
	Proved oil and gas properties		$	563,317			$	531,971			$	31,346		$	564,755			$	530,996			$	33,759
	Unproved properties		2,089				—				2,089			—				—				—
	Total		565,406				531,971				33,435			564,755				530,996				33,759
	Accumulated depreciation, depletion, amortization and impairment		(383,469		)		(356,255		)		(27,214		)	(413,704		)		(381,283		)		(32,421		)
	Net capitalized costs		$	181,937			$	175,716			$	6,221		$	151,051			$	149,713			$	1,338
	Cost incurred in oil and gas property acquisition and development activities are as follows:
			Years Ended December 31
			2011											2012											2013
			Total				U.S.				Canada			Total				U.S.				Canada			Total			U.S.			Canada
			(In thousands)
	Development costs		$	46,735			$	32,471			$	14,264		$	56,318			$	48,283			$	8,035		$	93,878		$	91,325		$	2,553
	Exploration costs		8,410				8,410				—			—				—				—			—			—			—
	Property acquisition costs		—				—				—			7,200				7,200				—			—			—			—
	Unproved		1,100				—				1,100			989				—				989			—			—			—
			$	56,245			$	40,881			$	15,364		$	64,507			$	55,483			$	9,024		$	93,878		$	91,325		$	2,553
	The results of operations for oil and gas producing activities for the three years ended December 31, 2011, 2012 and 2013 are as follows:
			Years Ended December 31,
			2011											2012											2013
			Total				U.S.				Canada			Total				U.S.				Canada			Total			U.S.			Canada
			(In thousands)
	Revenues		$	64,615			$	63,105			$	1,510		$	68,499			$	65,590			$	2,909		$	94,275		$	92,268		$	2,007
	Production costs		(27,347		)		(26,552		)		(795		)	(31,419		)		(29,166		)		(2,253		)	(33,871		)	(31,642		)	(2,229		)
	Depreciation, depletion, and amortization		(15,595		)		(14,914		)		(681		)	(22,767		)		(20,704		)		(2,063		)	(26,072		)	(25,028		)	(1,044		)
	Proved property impairment		—				—				—			(19,774		)		—				(19,774		)	(6,025		)	—			(6,025		)
	General and administrative		(2,352		)		(1,698		)		(654		)	(2,679		)		(1,980		)		(699		)	(3,350		)	(2,471		)	(879		)
	Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)		$	19,321			$	19,941			$	(620	)	$	(8,140	)		$	13,740			$	(21,880	)	$	24,957		$	33,127		$	(8,170	)
	Depletion rate per barrel of oil equivalent		$	12.26			$	11.96			$	27.58		$	15.59			$	14.74			$	37.48		$	16.59		$	16.32		$	27.37
	Estimated Quantities of Proved Oil and Gas Reserves
	The following table presents the Company’s estimate of its net proved oil and gas reserves as of December 31, 2011, 2012, and 2013.  The Company’s management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties.  Accordingly, the estimates are expected to change as future information becomes available.  The estimates have been predominately prepared by independent petroleum reserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States and Canada.
	Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, the average prior 12-month-first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows for the periods presented.
			Total									United States								Canada
			Oil/NGL			Gas			Oil			Oil/NGL		Gas			Oil			Oil/NGL			Gas		Oil
									Equivalents								Equivalents								Equivalents
			(MBbl)			(MMcf)			(MBoe)			(MBbl)		(MMcf)			(MBoe)			(MBbl)			(MMcf)		(MBoe)
			(In thousands)
	Proved developed and undeveloped reserves:
	Balance at December 31, 2010		9,794			84,913			23,947			9,718		84,523			23,806			76			390		141
	Revisions of previous estimates		2,290			(13,009	)		122			2,290		(13,009	)		122			—			—		—
	Extensions and discoveries		2,703			4,393			3,435			2,326		1,837			2,632			377			2,556		803
	Sales of minerals in place		—			—			—			—		—			—			—			—		—
	Production		(568	)		(4,222	)		(1,272	)		(554	)	(4,160	)		(1,247	)		(14	)		(62	)	(25	)
	Balance at December 31, 2011		14,219			72,075			26,232			13,780		69,191			25,313			439			2,884		919
	Revisions of previous estimates		1,574			(7,470	)		328			1,774		(5,786	)		809			(200	)		(1,684	)	(481	)
	Extensions and discoveries		5,809			6,983			6,973			5,809		6,983			6,973			—			—		—
	Purchases of minerals in place		1			69			13			1		69			13			—			—		—
	Sales of minerals in place		(850	)		(6,376	)		(1,913	)		(850	)	(6,376	)		(1,913	)		—			—		—
	Production		(797	)		(4,097	)		(1,481	)		(763	)	(3,982	)		(1,427	)		(34	)		(115	)	(54	)
	Balance at December 31, 2012		19,956			61,184			30,152			19,751		60,099			29,768			205			1,085		384
	Revisions of previous estimates		999			(5,123	)		145			1,073		(4,804	)		270			(74	)		(319	)	(125	)
	Extensions and discoveries		10,746			3,610			11,348			10,746		3,610			11,348			—			—		—
	Purchases of minerals in place		—			—			—			—		—			—			—			—		—
	Sales of minerals in place		(7,748	)		(8,141	)		(9,105	)		(7,748	)	(8,141	)		(9,105	)		—			—		—
	Production		(1,000	)		(3,421	)		(1,570	)		(976	)	(3,343	)		(1,533	)		(24	)		(78	)	(37	)
	Balance at December 31, 2013		22,953			48,109			30,970			22,846		47,421			30,748			107			688		222
			Total									United States								Canada
			Oil/NGL			Gas			Oil			Oil/NGL		Gas			Oil			Oil/NGL			Gas		Oil
									Equivalents								Equivalents								Equivalents
		(MBbl)			(MMcf)			(MBoe)			(MBbl)		(MMcf)			(MBoe)			(MBbl)			(MMcf)		(MBoe)
		(In thousands)
Proved Developed Reserves:
December 31, 2011		7,761			42,582			14,858			7,433		40,451			14,175			328			2,131		683
December 31, 2012		8,650			41,220			15,520			8,531		40,723			15,318			119			497		202
December 31, 2013		8,310			31,572			13,572			8,284		31,424			13,521			26			148		51
Proved Undeveloped Reserves:
December 31, 2011		6,460			29,493			11,376			6,348		28,740			11,138			112			753		238
December 31, 2012		11,306			19,964			14,634			11,220		19,376			14,450			86			588		184
December 31, 2013		14,640			16,537			17,397			14,560		15,996			17,226			80			541		171
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The Company’s proved oil and gas reserves have been estimated by the Company with the assistance of an independent petroleum engineering firm (DeGolyer & MacNaughton) as of December 31, 2011, 2012 and 2013. The following information has been prepared in accordance with SEC rules and accounting standards based on the 12-month first-day-of-the-month average prices in accordance with provisions of the FASB’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis and net operating losses associated with the properties.  Since prices used in the calculation are average prices for 2013, the standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year.
The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.    All reports by DeGolyer and MacNaughton were developed utilizing studies performed by DeGolyer and MacNaughton and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers.  The report of DeGolyer and MacNaughton dated February 13, 2014, which contains further discussions of the reserve estimates and evaluations prepared by DeGolyer and MacNaughton as well as the qualifications of DeGolyer and MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.
Estimates of proved reserves at December 31, 2011, 2012 and 2013 were based on studies performed by our independent petroleum engineers assisted by the Engineering and Operations departments of Abraxas.  The Engineering department is directly responsible for Abraxas’ reserve evaluation process.  The Vice President of Engineering is the manager of this department and is the primary technical person responsible for this process.  The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and has 35 years of experience in reserve evaluations. The Vice President of Engineering is a Registered Professional Engineer in the State of Texas.  The operations department of Abraxas assisted in the process, and consists of four petroleum engineers with Bachelor degrees in Petroleum Engineering, and various other technical professionals.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted to represent the fair market value of the Company’s proved oil and gas reserves.  An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table below sets forth the Standardized Measure of our proved oil and gas reserves for the three years ended December 31, 2011, 2012 and 2013:
		Years Ended December 31,
		2011											2012											2013
		Total				U.S.				Canada			Total				U.S.				Canada			Total			U.S.			Canada
		(In thousands)
Future cash inflows		$	1,471,352			$	1,420,013			$	51,339		$	1,784,920			$	1,766,515			$	18,405		$	2,244,846		$	2,234,632		$	10,214
Future production costs		(544,970		)		(532,056		)		(12,914		)	(642,706		)		(634,903		)		(7,803		)	(754,722		)	(751,058		)	(3,664		)
Future development costs		(228,804		)		(224,254		)		(4,550		)	(328,554		)		(324,704		)		(3,850		)	(467,206		)	(463,456		)	(3,750		)
Future income tax expense		(106,839		)		(104,279		)		(2,560		)	(149,625		)		(149,625		)		—			(244,394		)	(244,394		)	—
Future net cash flows		590,739				559,424				31,315			664,035				657,283				6,752			778,524			775,724			2,800
Discount		(321,657		)		(310,516		)		(11,141		)	(385,890		)		(383,271		)		(2,619		)	(437,539		)	(436,077		)	(1,462		)
Standardized Measure of discounted future net cash relating to proved reserves		$	269,082			$	248,908			$	20,174		$	278,145			$	274,012			$	4,133		$	340,985		$	339,647		$	1,338
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
		Year Ended December 31,
		2011				2012				2013
		(In thousands)
Standardized Measure, beginning of year		$	196,993			$	269,082			$	278,145
Sales and transfers of oil and gas produced, net of production costs		(37,171		)		(37,080		)		(60,403		)
Net change in prices and development and production costs from prior year		92,886				60,710				169,969
Extensions, discoveries, and improved recovery, less related costs		47,765				73,236				156,456
Sales of minerals in place		—				(20,089		)		(125,533		)
Purchased of minerals in place		—				131				—
Revisions of previous quantity estimates		1,329				3,355				2,930
Change in timing and other		(23,501		)		(88,309		)		(62,861		)
Change in future income tax expense		(28,918		)		(9,799		)		(45,532		)
Accretion of discount		19,699				26,908				27,814
Standardized Measure, end of year		$	269,082			$	278,145			$	340,985
The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates:
		Year Ended December 31,
		2011				2012				2013
Oil (per Bbl) (1)		$	96.19			$	95.14			$	97.33
Gas (per MMbtu) (2)		$	4.16			$	2.86			$	3.67
Oil (per Bbl) (3)		$	88.58			$	88.26			$	95.9
Gas (per MMBtu) (4)		$	3.73			$	2.61			$	3.65
NGL’s (per Bbl) (5)		$	50.21			$	36.76			$	31.98
_____________________
-1	The quoted oil price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2011, 2012 and 2013.
-2	The quoted gas price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2011, 2012 and 2013.
-3	The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
-4	The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
-5	The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.

Organization_and_Significant_A1

Organization and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Nature of Operations	'
	Nature of Operations
	We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States and Canada.  Our oil and gas assets are located in three operating regions in the United States, the Rocky Mountain, Permian Basin and onshore Gulf Coast, and in the province of Alberta, Canada.
	The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”) and its wholly-owned foreign subsidiary, Canadian Abraxas Petroleum, ULC (“Canadian Abraxas”). The term “Partnership” refers only to Abraxas Energy Partners, L.P.
	Canadian Abraxas’ assets and liabilities are translated to U.S. dollars at period-end exchange rates.  Income and expense items are translated at average rates of exchange prevailing during the period.  Translation adjustments are accumulated as a separate component of stockholders’ equity.
Rig Accounting	'
	Rig Accounting
	In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates holds an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced.
Use of Estimates	'
	Use of Estimates
	The preparation of consolidated 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 disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
Concentration of Credit Risk	'
	Concentration of Credit Risk
	Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts.  Accounts receivable are generally from companies with significant oil and gas marketing activities.  The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties.
	The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality.
Cash and Equivalents	'
	Cash and Equivalents
	Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.
Accounts Receivable	'
	Accounts Receivable
	Accounts receivable are reported net of an allowance for doubtful accounts of approximately $105,000 and $407,000 at December 31, 2012 and 2013, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.
Oil and Gas Properties	'
	Oil and Gas Properties
	The Company follows the full cost method of accounting for oil and gas properties.  Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. As of December 31, 2011, our net capitalized costs of oil and gas properties in the United States and Canada did not exceed the present value of our estimated proved reserves. As of December 31, 2012, net capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved reserves; however, the net capitalized costs of oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $19.8 million resulting in a write down for the year ended December 31, 2012. Write downs of $1.3 million, $11.8 million and $6.7 million were taken in the second, third and fourth quarters of 2012, respectively.
Other Property and Equipment	'
	Other Property and Equipment
	Other property and equipment are recorded on the basis of cost.  Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method.  Major renewals and improvements are recorded as additions to the property and equipment accounts.  Repairs that do not improve or extend the useful lives of assets are expensed.
Estimates of Proved Oil and Gas Reserves	'
	Estimates of Proved Oil and Gas Reserves
	Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:
	•the quality and quantity of available data;
	•the interpretation of that data;
	•the accuracy of various mandated economic assumptions; and
	•the judgment of the persons preparing the estimate.
	Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the Engineering and Operations departments of Abraxas. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may cause material revisions to the estimate.
	In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the average 12 month first-day-of-month pricing for the years ended December 31, 2012 and 2013, and costs as of December 31, 2012 and 2013. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.
	The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields.
Derivative Instruments and Hedging Activities	'
	Derivative Instruments and Hedging Activities
	The Company enters into agreements to hedge the risk of future oil and gas price fluctuations.  Such agreements are in the form of fixed price swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. The Company does not enter into speculative hedges.
	The Company accounts for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for hedge accounting rules as prescribed by Accounting Standards Codification (“ASC”) 815. Accordingly, we do not account for our derivative instruments as cash flow hedges for financial reporting purposes and instead record their fair value on the balance sheet with adjustments to the carrying value of the instruments being recognized as a gain or loss in the current period.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value.  The carrying value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments.  For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.
Share-Based Payments	'
	Share-Based Payments
	The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors.  Options granted are valued at the date of grant and expense is recognized over the vesting period. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period.
Restoration, Removal and Environmental Liabilities	'
	Restoration, Removal and Environmental Liabilities
	The Company is subject to extensive Federal, provincial, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
	Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.
	The Company accounts for asset retirement obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements.
Revenue Recognition and Major Purchasers	'
	Revenue Recognition and Major Purchasers
	The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. The Company utilizes the sales method to account for gas production imbalances.  Under this method, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2012 and 2013.
Deferred Financing Fees	'
	Deferred Financing Fees
	Deferred financing fees are being amortized on the effective yield basis over the term of the related debt arrangements.
Income Taxes	'
	Income Taxes
	The Company records deferred income taxes using the asset and liability method.  Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10. Therefore, we have established a valuation allowance of $75.6 million for deferred tax assets at December 31, 2013.
Accounting for Uncertainty in Income Taxes	'
	Accounting for Uncertainty in Income Taxes
	ASC 740 provides guidance on accounting for uncertainty in income taxes.  ASC 740 is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC 740 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.
	Under ASC 740, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.
	Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense.
Other Comprehensive Income (Loss)	'
	Other Comprehensive Income (Loss)
	ASC 220 requires disclosure of comprehensive income (loss), which includes reported net income (loss) as adjusted for other comprehensive income (loss). Other Comprehensive income (loss) for the Company is the change in the unrealized value of investments and foreign currency translation adjustments.

Organization_and_Significant_A2

Organization and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Asset Retirement Obligations	'
	The following table summarizes the Company’s asset retirement obligations during the two years ended December 31:
		2012			2013
	Beginning asset retirement obligation	$	8,412		$	11,381
	New wells placed on production and other	330			222
	Deletions related to property disposals and plugging costs	(423		)	(2,491		)
	Accretion expense	474			638
	Revisions	2,588			138
	Ending asset retirement obligation	$	11,381		$	9,888

Joint_Venture_Tables

Joint Venture (Tables)	12 Months Ended
	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]	'
Financial data from Blue Eagle's	'
	The following is condensed financial data from Blue Eagle’s August 31, 2012 (date of dissolution) and December 31, 2011 financial statements:
		As of
		August 31,
		2012
	Balance Sheets:
	Assets:
	Current assets	$	7,921
	Oil and gas properties	75,741
	Other assets	30
	Total assets	$	83,692
	Liabilities and Members’ Capital:
	Current liabilities	$	1,474
	Other liabilities	48
	Members’ capital	82,170
	Total liabilities and members’ capital	$	83,692
		Year Ended			Year Ended
		December 31,			December 31,
	Statement of Operations:	2011			2012 (1)
		(In thousands)
	Revenue	$	12,579		$	12,106
	Operating expenses	7,138			7,144
	Other income	(11		)	(4		)
	Net income	$	5,452		$	4,966
	(1) Through August 31, 2012

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-term Debt	'
	The following is a description of the Company’s debt as of December 31, 2012 and 2013, respectively:
			December 31,			December 31,
			2012			2013
			(In thousands)
	Senior secured credit facility		$	113,000		$	33,000
	Rig loan agreement		7,000			6,378
	Real estate lien note		4,758			4,554
			124,758			43,932
	Less current maturities		(657		)	(2,142		)
			$	124,101		$	41,790
Maturities of Long-term Debt	'
	Maturities of long-term debt are as follows:
	Year ending December 31, (In thousands)
	2014	$	2,142
	2015	35,235
	2016	2,332
	2017	608
	2018	262
	Thereafter	3,353
		$	43,932

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Major Components of Property and Equipment	'
	The major components of property and equipment, at cost, are as follows:
		Estimated Useful Life	December 31,
			2012		2013
		Years	(In thousands)
	Oil and gas properties	—	$	565,406	$	564,755
	Equipment and other	Mar-39	19,052		17,237
	Drilling rig	15	18,781		21,722
			$	603,239	$	603,714

Stockbased_Compensation_Option1

Stock-based Compensation, Option Plans and Warrants (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Weighted Average Assumptions Used in Calculating Fair Value of Options	'
	The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. The fair value for these options was estimated at the date of grant using the following weighted average assumptions for 2011, 2012 and 2013:
		2011				2012				2013
	Weighted average value per option granted during the period	$	3.11			$	2.17			$	1.73
	Assumptions: (1)(2)
	Expected dividend yield	—		%		—		%		—		%
	Volatility	80		%		81.4		%		81.2		%
	Risk free interest rate	2.21		%		1.19		%		1.24		%
	Expected life (years)	6.4				6.7				6.5
	Fair value of options granted (in thousands)	$	2,506			$	1,324			$	1,444
	(1)    The estimated future forfeiture rate is based on the Company’s historical forfeiture rate.
	(2)    The Company does not pay dividends on its common stock.
Schedule of Stock Option Activity	'
	The following table is a summary of the Company’s stock option activity for the three years ended December 31:
		Options			Weighted average				Weighted
		(000s)			exercise price				average		Intrinsic
									remaining life		value
											per share
	Options outstanding December 31, 2010	4,820			$	2.23
	Granted	807			4.37
	Exercised	(530	)		1.54
	Forfeited/Expired	(341	)		3.01
	Options outstanding December 31, 2011	4,756			$	2.61
	Granted	610			3.01
	Exercised	(391	)		1.11
	Forfeited/Expired	(214	)		2.8
	Options outstanding December 31, 2012	4,761			$	2.77
	Granted	836			$	2.43
	Exercised	(166	)		1.18
	Forfeited/Expired	(31	)		2.58
	Options outstanding December 31, 2013	5,400			$	2.77			6.2		$	1.98
	Exercisable at end of year	3,828			$	1.93			5.3		$	1.93
	Other information pertaining to the Company’s stock option activity for the three years ended December 31:
		2011				2012				2013
	Weighted average grant date fair value of stock options granted  (per share)	$	3.11			$	2.17			$	1.73
	Total fair value of options vested (000’s)	$	1,230			$	1,497			$	1,670
	Total intrinsic value of options exercised (000’s)	$	1,584			$	414			$	275
Range Of Stock Option Prices and Weighted Average Remaining Life of Outstanding Options	'
	The following table represents the range of stock option prices and the weighted average remaining life of outstanding options as of December 31:
		Options outstanding									Exercisable
					Weighted		Weighted						Weighted	Weighted
		Number			average		average				Number		average	average
		outstanding			remaining		exercise				exercisable		remaining	exercise
					life		price						life	price
	0.68 – 0.99	627,450			5.21		$	0.99			627,450		5.21	$	0.99
	1.00 – 1.99	1,114,672			6.28		$	1.75			964,672		5.91	$	1.71
	2.00 – 2.99	1,670,025			7.66		$	2.32			816,925		6.57	$	2.31
	3.00 – 3.99	745,563			6.73		$	3.64			399,427		5.49	$	3.62
	4.00 – 4.99	1,168,500			4.47		$	4.58			945,250		3.83	$	4.55
	5.00 – 6.05	74,000			2.15		$	6.05			74,000		2.15	$	6.05
		5,400,210									3,827,724
Schedule of Restricted Stock Activity	'
	The following table is a summary of the Company’s restricted stock activity for the three years ended December 31:
		Number			Weighted
		of			average
		Shares			grant date
					fair value
	Unvested December 31, 2010	400,295			$	2.02
	Granted	408,676			3.67
	Vested/Released	(156,890	)		2.24
	Forfeited	(22,310	)		2.27
	Unvested December 31, 2011	629,771			$	3.03
	Granted	89,860			2.12
	Vested/Released	(229,172	)		2.57
	Forfeited	(8,434	)		2.42
	Unvested December 31, 2012	482,025			$	3.09
	Granted	48,222			2.69
	Vested/Released	(169,700	)		2.66
	Forfeited	(5,307	)		3.08
	Unvested December 31, 2013	355,240			$	3.24

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Components of Deferred Tax Liabilities and Assets	'
	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 purposes.  Significant components of the Company’s deferred tax liabilities and assets are as follows:
		Years Ended December 31,
		2011			2012			2013
		(In thousands)
	Deferred tax liabilities:
	Marketable securities	$	36		$	28		$	—
	Canada full cost pool	377			—			—
	Investment in Blue Eagle	7,527			—			—
	Hedge contracts	345			—			—
	Other	—			—			3,152
	Total deferred tax liabilities	8,285			28			3,152
	Deferred tax assets:
	U.S. full cost pool	29,976			13,837			11,725
	Canada full cost pool	—			3,720			4,081
	Depletion carryforward	4,842			4,930			4,743
	U.S. net operating loss  carryforward	52,564			59,362			49,667
	Canada net operating loss carryforward	2,151			4,196			5,736
	Alternative minimum tax credit	422			422			1,369
	Hedge contracts	—			2,231			1,397
	Other	1,811			1,042			—
	Total deferred tax assets	91,766			89,740			78,718
	Valuation allowance for deferred tax assets	(83,481		)	(89,712		)	(75,566		)
	Net deferred tax assets	8,285			28			3,152
	Net deferred tax	$	—		$	—		$	—
Components of Provision (Benefit) for Income Taxes	'
	Significant components of the provision (benefit) for income taxes are as follows:
		Years ended December 31,
		2011			2012			2013
		(In thousands)
	Current:
	Federal	$	(77	)	$	310		$	632
	State	—			—			68
	Foreign	—			—			—
		$	(77	)	$	310		$	700
	Deferred:
	Federal	$	—		$	—		$	—
	Foreign	—			—			—
		$	—		$	—		$	—
Reconciliation of Income Tax Computed At U.S. Federal Statutory Tax Rates to Income Tax Expense	'
	The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:
		Years ended December 31,
		2011			2012			2013
		(In thousands)
	Tax (expense) benefit at U.S. statutory rates (35%)	$	(4,809	)	$	6,468		$	(13,771	)
	(Increase) decrease in deferred tax asset valuation allowance	5,408			(6,231		)	14,146
	Rate differential for non U.S. income	(46		)	(1,533		)	(574		)
	State income taxes	—			—			(47		)
	Accrual of prior year federal taxes (2009)	—			(310		)	(81		)
	Permanent differences	(533		)	(732		)	(743		)
	Increase in asset  for partnership distribution	—			1,945			—
	Other	57			83			370
		$	77		$	(310	)	$	(700	)

Earnings_per_Share_Tables

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Computation of Basic and Diluted Net Income (Loss) Per Share	'
	The following table sets forth the computation of basic and diluted earnings per share:
		Years ended December 31:
		2011		2012			2013
		(In thousands, except per share data)
	Numerator:
	Net income (loss)	$	13,743	$	(18,791	)	$	38,647
	Denominator:
	Denominator for basic earnings per share – weighted-average common shares outstanding	90,151		91,914			92,451
	Effect of dilutive securities:	2,093		—			1,087
	Stock options, restricted shares and warrants
	Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options, restricted shares and warrants	92,244		91,914			93,538
	Net income (loss) per common share  – basic	$	0.15	$	(0.20	)	$	0.42
	Net income (loss) per common share – diluted	$	0.15	$	(0.20	)	$	0.41

Quarterly_Results_of_Operation1

Quarterly Results of Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Results of Operations for Fiscal Quarters	'
	Selected results of operations for each of the fiscal quarters during the years ended December 31, 2012 and 2013 are as follows:
		1st		2nd			3rd			4th
		Quarter		Quarter			Quarter			Quarter
		(In thousands, except per share data)
	Year Ended December 31, 2012
	Net revenue	$	16,396	$	15,938		$	17,170		$	19,069
	Operating income	$	2,224	$	(23	)	$	(11,359	)	$	(7,190	)
	Net (loss) income	$	817	$	10,903		$	(18,644	)	$	(11,867	)
	Net (loss) income per common share – basic	$	0.01	$	0.12		$	(0.20	)	$	(0.13	)
	Net (loss) income per common share – diluted	$	0.01	$	0.12		$	(0.20	)	$	(0.13	)
	Year Ended December 31, 2013
	Net revenue	$	21,196	$	21,494		$	29,095		$	22,546
	Operating income (loss)	$	3,768	$	2,867		$	11,161		$	(2,869	)
	Net income (loss) income	$	595	$	7,866		$	3,190		$	26,996
	Net income (loss) per common share – basic	$	0.01	$	0.09		$	0.03		$	0.29
	Net income (loss) per common share – diluted	$	0.01	$	0.08		$	0.03		$	0.29

Business_Segments_Tables

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Geographic Operating Segment and Asset Data	'
	The following tables provide the Company’s geographic operating segment data as of and for the year ended December 31, 2011, 2012 and 2013:
		Year Ended December 31, 2011
		U.S.		Canada			Corporate			Total
		(In thousands)
	Revenues:
	Oil and gas production	$	63,105	$	1,510		$	—		$	64,615
	Other	—		—			7			7
		63,105		1,510			7			64,622
	Costs and expenses:
	Lease operating	20,788		793			—			21,581
	Production taxes	5,764		2			—			5,766
	Depreciation, depletion and amortization	15,236		709			249			16,194
	Impairment	—		—			—			—
	General and administrative	1,698		654			7,081			9,433
	Net interest	448		4			4,439			4,891
	Amortization of deferred financing fees	—		—			1,762			1,762
	Loss on derivative contracts - realized	—		—			676			676
	Gain on derivative contracts - unrealized	—		—			(7,476		)	(7,476		)
	Earnings from equity method investment	—		—			(2,187		)	(2,187		)
	Other	—		—			316			316
	Income tax	—		—			(77		)	(77		)
	Income (loss)	$	19,171	$	(652	)	$	(4,776	)	$	13,743
		Year Ended December 31, 2012
		U.S.		Canada			Corporate			Total
		(In thousands)
	Revenues:
	Oil and gas production	$	65,590	$	2,909		$	—		$	68,499
	Other	—		—			74			74
		65,590		2,909			74			68,573
	Costs and expenses:
	Lease operating	22,578		2,228			—			24,806
	Production taxes	6,588		25			—			6,613
	Depreciation, depletion and amortization	20,704		2,063			249			23,016
	Impairment	—		19,774			—			19,774
	General and administrative	1,980		699			8,033			10,712
	Net interest	457		17			5,042			5,516
	Amortization of deferred financing fees	—		—			937			937
	Loss on derivative contracts - realized	—		—			459			459
	Gain on derivative contracts - unrealized	—		—			(2,669		)	(2,669		)
	Earnings from equity method investment	—		—			(2,207		)	(2,207		)
	Income tax expense	—		—			310			310
	Other	—		—			97			97
	Income (loss)	$	13,283	$	(21,897	)	$	(10,177	)	$	(18,791	)
		Year Ended December 31, 2013
		U.S.		Canada			Corporate			Total
		(In thousands)
	Revenues:
	Oil and gas production	$	92,268	$	2,007		$	—		$	94,275
	Other	—		—			56			56
		92,268		2,007			56			94,331
	Costs and expenses:
	Lease operating	23,205		2,156			—			25,361
	Production taxes	8,437		73			—			8,510
	Depreciation, depletion and amortization	25,338		1,045			249			26,632
	Impairment	—		6,025			—			6,025
	General and administrative	2,471		879			9,526			12,876
	Net interest	615		23			3,939			4,577
	Amortization of deferred financing fees	—		—			1,367			1,367
	Gain on sale of properties	—		—			(33,377		)	(33,377		)
	Loss on derivative contracts - realized	—		—			5,035			5,035
	Gain on derivative contracts - unrealized	—		—			(2,561		)	(2,561		)
	Income tax	—		—			700			700
	Other	—		—			539			539
Income (loss)	$	32,202	$	(8,194	)	$	14,639		$	38,647
The following table provides the Company’s geographic asset data as of December 31, 2012 and December 31, 2013:
Segment Assets:	December 31,		December 31,
	2012		2013
	(In thousands)
United States	$	223,253	$	213,212
Canada	7,053		1,640
Corporate	10,301		8,798
	$	240,607	$	223,650

Hedging_Program_and_Derivative1

Hedging Program and Derivatives (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Contract Position	'
	The following table sets forth the summary position of our derivative contracts as of December 31, 2013:
		Oil - WTI					Oil - Brent					Oil - LLS
	Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)			Daily Volume (Bbl)			Swap Price (per Bbl)		Daily Volume (Bbl)	Swap Price (per Bbl)
	2014	687		$	94.16		505			$	100.56	100	$	101.26
	2015	560		$	83.03		500			$	97.04	—	$	—
	2016	963		$	84.1		—			$	—	—	$	—
	2017	500		$	84.18		—			$	—	—	$	—
Impact of Derivative Contracts on Balance Sheet	'
	The following table illustrates the impact of derivative contracts on the Company’s balance sheet:
	Fair Value of Derivative Instruments as of December 31, 2012
		Asset Derivatives				Liability Derivatives
	Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value			Balance Sheet Location		Fair Value
	Commodity price derivatives	Derivatives – current	$	41		Derivatives – current		$	3,462
	Commodity price derivatives	Derivatives – long-term	594			Derivatives – long-term		3,568
			$	635				$	7,030
	Fair Value of Derivative Instruments as of December 31, 2013
		Asset Derivatives				Liability Derivatives
	Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value			Balance Sheet Location		Fair Value
	Commodity price derivatives	Derivatives – current	$	85		Derivatives – current		$	2,728
	Commodity price derivatives	Derivatives – long-term	925			Derivatives – long-term		2,274
			$	1,010				$	5,002

Financial_Instruments_Tables

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Assets and Liabilities Measured at Fair Value	'
	A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and 2013, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):
		Quoted Prices		Significant
		in Active		Other
		Markets for		Observable		Significant		Balance as of
		Identical		Inputs		Unobservable		December 31,
		Assets		(Level 2)		Inputs (Level 3)		2012
		(Level 1)
	Assets:
	Investment in common stock	$	78	$	—	$	—	$	78
	NYMEX Fixed Price Derivative contracts	—		635		—		635
	Total Assets	$	78	$	635	$	—	$	713
	Liabilities:
	NYMEX Fixed Price Derivative contracts	$	—	$	7,030	$	—	$	7,030
	Total Liabilities	$	—	$	7,030	$	—	$	7,030
		Quoted Prices		Significant
		in Active		Other
		Markets for		Observable		Significant		Balance as of
		Identical		Inputs		Unobservable		December 31,
		Assets		(Level 2)		Inputs (Level 3)		2013
		(Level 1)
	Assets:
	NYMEX Fixed Price Derivative contracts	$	—	$	1,010	$	—	$	1,010
	Total Assets	$	—	$	1,010	$	—	$	1,010
	Liabilities:
	NYMEX Fixed Price Derivative contracts	$	—	$	5,002	$	—	$	5,002
	Total Liabilities	$	—	$	5,002	$	—	$	5,002

Supplemental_Oil_and_Gas_Discl1

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Capitalized Costs Relating to Oil and Gas Producing Activities	'
	The accompanying table presents information concerning the Company’s oil and gas producing activities as required by ASC 932-235, “Disclosures about Oil and Gas Producing Activities.”  Capitalized costs relating to oil and gas producing activities are as follows:
			Years Ended December 31
			2012											2013
			Total				U.S.				Canada			Total				U.S.				Canada
			(In thousands)
	Proved oil and gas properties		$	563,317			$	531,971			$	31,346		$	564,755			$	530,996			$	33,759
	Unproved properties		2,089				—				2,089			—				—				—
	Total		565,406				531,971				33,435			564,755				530,996				33,759
	Accumulated depreciation, depletion, amortization and impairment		(383,469		)		(356,255		)		(27,214		)	(413,704		)		(381,283		)		(32,421		)
	Net capitalized costs		$	181,937			$	175,716			$	6,221		$	151,051			$	149,713			$	1,338
Cost Incurred in Oil and Gas Property Acquisition and Development Activities	'
	Cost incurred in oil and gas property acquisition and development activities are as follows:
			Years Ended December 31
			2011											2012											2013
			Total				U.S.				Canada			Total				U.S.				Canada			Total			U.S.			Canada
			(In thousands)
	Development costs		$	46,735			$	32,471			$	14,264		$	56,318			$	48,283			$	8,035		$	93,878		$	91,325		$	2,553
	Exploration costs		8,410				8,410				—			—				—				—			—			—			—
	Property acquisition costs		—				—				—			7,200				7,200				—			—			—			—
	Unproved		1,100				—				1,100			989				—				989			—			—			—
			$	56,245			$	40,881			$	15,364		$	64,507			$	55,483			$	9,024		$	93,878		$	91,325		$	2,553
Results of Operations for Oil and Gas Producing Activities	'
	The results of operations for oil and gas producing activities for the three years ended December 31, 2011, 2012 and 2013 are as follows:
			Years Ended December 31,
			2011											2012											2013
			Total				U.S.				Canada			Total				U.S.				Canada			Total			U.S.			Canada
			(In thousands)
	Revenues		$	64,615			$	63,105			$	1,510		$	68,499			$	65,590			$	2,909		$	94,275		$	92,268		$	2,007
	Production costs		(27,347		)		(26,552		)		(795		)	(31,419		)		(29,166		)		(2,253		)	(33,871		)	(31,642		)	(2,229		)
	Depreciation, depletion, and amortization		(15,595		)		(14,914		)		(681		)	(22,767		)		(20,704		)		(2,063		)	(26,072		)	(25,028		)	(1,044		)
	Proved property impairment		—				—				—			(19,774		)		—				(19,774		)	(6,025		)	—			(6,025		)
	General and administrative		(2,352		)		(1,698		)		(654		)	(2,679		)		(1,980		)		(699		)	(3,350		)	(2,471		)	(879		)
	Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)		$	19,321			$	19,941			$	(620	)	$	(8,140	)		$	13,740			$	(21,880	)	$	24,957		$	33,127		$	(8,170	)
	Depletion rate per barrel of oil equivalent		$	12.26			$	11.96			$	27.58		$	15.59			$	14.74			$	37.48		$	16.59		$	16.32		$	27.37
Proved Developed and Undeveloped Reserves	'
	Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, the average prior 12-month-first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows for the periods presented.
			Total									United States								Canada
			Oil/NGL			Gas			Oil			Oil/NGL		Gas			Oil			Oil/NGL			Gas		Oil
									Equivalents								Equivalents								Equivalents
			(MBbl)			(MMcf)			(MBoe)			(MBbl)		(MMcf)			(MBoe)			(MBbl)			(MMcf)		(MBoe)
			(In thousands)
	Proved developed and undeveloped reserves:
	Balance at December 31, 2010		9,794			84,913			23,947			9,718		84,523			23,806			76			390		141
	Revisions of previous estimates		2,290			(13,009	)		122			2,290		(13,009	)		122			—			—		—
	Extensions and discoveries		2,703			4,393			3,435			2,326		1,837			2,632			377			2,556		803
	Sales of minerals in place		—			—			—			—		—			—			—			—		—
	Production		(568	)		(4,222	)		(1,272	)		(554	)	(4,160	)		(1,247	)		(14	)		(62	)	(25	)
	Balance at December 31, 2011		14,219			72,075			26,232			13,780		69,191			25,313			439			2,884		919
	Revisions of previous estimates		1,574			(7,470	)		328			1,774		(5,786	)		809			(200	)		(1,684	)	(481	)
	Extensions and discoveries		5,809			6,983			6,973			5,809		6,983			6,973			—			—		—
	Purchases of minerals in place		1			69			13			1		69			13			—			—		—
	Sales of minerals in place		(850	)		(6,376	)		(1,913	)		(850	)	(6,376	)		(1,913	)		—			—		—
	Production		(797	)		(4,097	)		(1,481	)		(763	)	(3,982	)		(1,427	)		(34	)		(115	)	(54	)
	Balance at December 31, 2012		19,956			61,184			30,152			19,751		60,099			29,768			205			1,085		384
	Revisions of previous estimates		999			(5,123	)		145			1,073		(4,804	)		270			(74	)		(319	)	(125	)
	Extensions and discoveries		10,746			3,610			11,348			10,746		3,610			11,348			—			—		—
	Purchases of minerals in place		—			—			—			—		—			—			—			—		—
	Sales of minerals in place		(7,748	)		(8,141	)		(9,105	)		(7,748	)	(8,141	)		(9,105	)		—			—		—
	Production		(1,000	)		(3,421	)		(1,570	)		(976	)	(3,343	)		(1,533	)		(24	)		(78	)	(37	)
	Balance at December 31, 2013		22,953			48,109			30,970			22,846		47,421			30,748			107			688		222
			Total									United States								Canada
			Oil/NGL			Gas			Oil			Oil/NGL		Gas			Oil			Oil/NGL			Gas		Oil
									Equivalents								Equivalents								Equivalents
			(MBbl)			(MMcf)			(MBoe)			(MBbl)		(MMcf)			(MBoe)			(MBbl)			(MMcf)		(MBoe)
			(In thousands)
	Proved Developed Reserves:
	December 31, 2011		7,761			42,582			14,858			7,433		40,451			14,175			328			2,131		683
	December 31, 2012		8,650			41,220			15,520			8,531		40,723			15,318			119			497		202
	December 31, 2013		8,310			31,572			13,572			8,284		31,424			13,521			26			148		51
	Proved Undeveloped Reserves:
	December 31, 2011		6,460			29,493			11,376			6,348		28,740			11,138			112			753		238
	December 31, 2012		11,306			19,964			14,634			11,220		19,376			14,450			86			588		184
	December 31, 2013		14,640			16,537			17,397			14,560		15,996			17,226			80			541		171
Future Net Cash Inflows after Income Taxes Discounted At 10% Annual Discount Rate to Arrive At Standardized Measure	'
	Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table below sets forth the Standardized Measure of our proved oil and gas reserves for the three years ended December 31, 2011, 2012 and 2013:
			Years Ended December 31,
			2011											2012											2013
			Total				U.S.				Canada			Total				U.S.				Canada			Total			U.S.			Canada
			(In thousands)
	Future cash inflows		$	1,471,352			$	1,420,013			$	51,339		$	1,784,920			$	1,766,515			$	18,405		$	2,244,846		$	2,234,632		$	10,214
	Future production costs		(544,970		)		(532,056		)		(12,914		)	(642,706		)		(634,903		)		(7,803		)	(754,722		)	(751,058		)	(3,664		)
	Future development costs		(228,804		)		(224,254		)		(4,550		)	(328,554		)		(324,704		)		(3,850		)	(467,206		)	(463,456		)	(3,750		)
	Future income tax expense		(106,839		)		(104,279		)		(2,560		)	(149,625		)		(149,625		)		—			(244,394		)	(244,394		)	—
	Future net cash flows		590,739				559,424				31,315			664,035				657,283				6,752			778,524			775,724			2,800
	Discount		(321,657		)		(310,516		)		(11,141		)	(385,890		)		(383,271		)		(2,619		)	(437,539		)	(436,077		)	(1,462		)
	Standardized Measure of discounted future net cash relating to proved reserves		$	269,082			$	248,908			$	20,174		$	278,145			$	274,012			$	4,133		$	340,985		$	339,647		$	1,338
Analysis of Changes in Standardized Measure	'
	The following is an analysis of the changes in the Standardized Measure:
			Year Ended December 31,
			2011				2012				2013
			(In thousands)
	Standardized Measure, beginning of year		$	196,993			$	269,082			$	278,145
	Sales and transfers of oil and gas produced, net of production costs		(37,171		)		(37,080		)		(60,403		)
	Net change in prices and development and production costs from prior year		92,886				60,710				169,969
	Extensions, discoveries, and improved recovery, less related costs		47,765				73,236				156,456
	Sales of minerals in place		—				(20,089		)		(125,533		)
	Purchased of minerals in place		—				131				—
	Revisions of previous quantity estimates		1,329				3,355				2,930
	Change in timing and other		(23,501		)		(88,309		)		(62,861		)
	Change in future income tax expense		(28,918		)		(9,799		)		(45,532		)
	Accretion of discount		19,699				26,908				27,814
	Standardized Measure, end of year		$	269,082			$	278,145			$	340,985
Oil and Gas Prices Considered In Standardized Measure of Discounted Future Net Cash Flows	'
	The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates:
			Year Ended December 31,
			2011				2012				2013
	Oil (per Bbl) (1)		$	96.19			$	95.14			$	97.33
	Gas (per MMbtu) (2)		$	4.16			$	2.86			$	3.67
	Oil (per Bbl) (3)		$	88.58			$	88.26			$	95.9
	Gas (per MMBtu) (4)		$	3.73			$	2.61			$	3.65
	NGL’s (per Bbl) (5)		$	50.21			$	36.76			$	31.98
	_____________________
	-1	The quoted oil price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2011, 2012 and 2013.
	-2	The quoted gas price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2011, 2012 and 2013.
	-3	The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
	-4	The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
	-5	The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.

Organization_and_Significant_A3

Organization and Significant Accounting Policies (Details) (USD $)	3 Months Ended						12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	region						region
Nature of operations [Abstract]	'	'	'	'	'	'	'	'	'
Number of operating regions in domicile country	3	'	'	'	'	'	3	'	'
Accounts Receivable [Abstract]	'	'	'	'	'	'	'	'	'
Allowance for doubtful accounts	$407,000	'	'	$105,000	'	'	$407,000	$105,000	'
Oil and gas properties, full cost method of accounting:	'	'	'	'	'	'	'	'	'
Discount rate used in future net cash flows relating to proved oil and gas reserves (in hundredths)	'	'	'	'	'	'	10.00%	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'	'	'	'	'	'	'
Write downs of oil and gas properties	3,900,000	100,000	2,000,000	6,700,000	11,800,000	1,300,000	'	'	'
Share-Based Payments [Abstract]	'	'	'	'	'	'	'	'	'
Stock-based compensation expense	'	'	'	'	'	'	2,114,000	2,091,000	1,987,000
Entity's asset retirement obligation transactions [Roll Forward]	'	'	'	'	'	'	'	'	'
Beginning asset retirement obligation	'	'	'	'	'	'	11,381,000	8,412,000	'
New wells placed on production and other	'	'	'	'	'	'	222,000	330,000	'
Deletions related to property disposals and plugging costs	'	'	'	'	'	'	-2,491,000	-423,000	'
Accretion expense	'	'	'	'	'	'	-638,000	-474,000	-452,000
Revisions	'	'	'	'	'	'	138,000	2,588,000	'
Ending asset retirement obligation	9,888,000	'	'	11,381,000	'	'	9,888,000	11,381,000	8,412,000
Revenue Recognition and Major Purchasers [Abstract]	'	'	'	'	'	'	'	'	'
Entity wide revenue, major customers (in hundredths)	'	'	'	'	'	'	49.00%	39.00%	28.00%
Entity wide revenue, number of major purchasers of oil and gas	'	'	'	'	'	'	2	3	2
Income Taxes [Abstract]	'	'	'	'	'	'	'	'	'
Valuation allowance for deferred tax assets	75,566,000	'	'	89,712,000	'	'	75,566,000	89,712,000	83,481,000
Canada [Member]	'	'	'	'	'	'	'	'	'
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'	'	'	'	'	'	'
Exceeded amount of net capitalized cost over estimated proved reserves	$6,000,000	'	'	$19,800,000	'	'	$6,000,000	$19,800,000	'

Joint_Venture_Details

Joint Venture (Details) (USD $)	12 Months Ended			0 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 18, 2010	Dec. 31, 2012		Dec. 31, 2011	Aug. 18, 2010
				Blue Eagle [Member]	Blue Eagle [Member]		Blue Eagle [Member]	Blue Eagle [Member]
				acre				Rock Oil [Member]
Schedule of Equity Method Investments [Line Items]	'	'	'	'	'		'	'
Land contributed to Blue Eagle Energy, LLC (in acres)	'	'	'	8,333	'		'	'
Equity interest in joint venture	'	'	'	$25,000,000	'		'	$25,000,000
Payment to acquire interest in joint venture	'	'	'	25,000,000	'		'	'
Gain from equity method investments	0	2,207,000	2,187,000	'	'		'	'
Assets [Abstract]	'	'	'	'	'		'	'
Current assets	'	'	'	'	7,921,000		'	'
Oil and gas properties	'	'	'	'	75,741,000		'	'
Other assets	'	'	'	'	30,000		'	'
Total assets	'	'	'	'	83,692,000		'	'
Liabilities and Members' Capital [Abstract]	'	'	'	'	'		'	'
Current liabilities	'	'	'	'	1,474,000		'	'
Other liabilities	'	'	'	'	48,000		'	'
Members’ capital	'	'	'	'	82,170,000		'	'
Total liabilities and members’ capital	'	'	'	'	83,692,000		'	'
Statement of Operations [Abstract]	'	'	'	'	'		'	'
Revenue	'	'	'	'	12,106,000	[1]	12,579,000	'
Operating expenses	'	'	'	'	7,144,000	[1]	7,138,000	'
Other income	'	'	'	'	-4,000	[1]	-11,000	'
Net income	'	'	'	'	$4,966,000	[1]	$5,452,000	'
[1]	(1) Through August 31, 2012

Divestiture_of_NonCore_Propert1

Divestiture of Non-Core Properties (Details) (USD $)	1 Months Ended		3 Months Ended	12 Months Ended
	Dec. 31, 2013	Aug. 31, 2013	Sep. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
			acre
Divestiture of Non Core Properties [Abstract]	'	'	'	'	'	'
Net proceeds from divestiture of non-core properties	$71,400,000	'	$21,500,000	$6,600,000	'	'
Proceeds from Monetization of Assets	'	38,300,000	'	10,600,000	'	'
Area of Real Estate Property	'	'	2,563	'	'	'
Proceeds from other property sales during the year	'	'	'	600,000	'	'
Gain (Loss) on Sale of Property	$33,400,000	'	'	$33,377,000	$0	$0

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Feb. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Sep. 19, 2011

Jul. 20, 2013

Apr. 04, 2013

Dec. 31, 2013

Dec. 31, 2012

9-May-08

borrowing_base

Senior Secured Credit Facility [Member]

Senior Secured Credit Facility [Member]

Senior Secured Credit Facility [Member]

Senior Secured Credit Facility [Member]

Rig Loan Agreement [Member]

Rig Loan Agreement [Member]

Rig Loan Agreement [Member]

Rig Loan Agreement [Member]

Real Estate Lien Note [Member]

Real Estate Lien Note [Member]

Real Estate Lien Note [Member]

Real Estate Lien Note [Member]

Real Estate Lien Note [Member]

Minimum [Member]

Maximum [Member]

hp

Long-term debt [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

$43,932,000

$124,758,000

$33,000,000

$113,000,000

'

'

'

$6,378,000

$7,000,000

'

'

'

$4,554,000

$4,758,000

'

Less current maturities

-2,142,000

-657,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt – less current maturities

41,790,000

124,101,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Maturities of long-term debt [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2014

2,142,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2015

35,235,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2016

2,332,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2017

608,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2018

262,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Thereafter

3,353,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maturity date of debt instrument

'

'

30-Jun-15

'

'

'

14-Feb-17

'

'

'

'

'

'

'

'

Percentage added to reference rate (in hundredths)

'

'

0.50%

'

1.25%

2.25%

'

'

'

'

'

'

'

'

'

Credit Facility [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowing capacity

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

5,400,000

Current borrowing base

130,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of reserve reports prepared by independent petroleum engineers

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of reserve report prepared internally

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of borrowing base redetermination

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of borrowing base redetermination

'6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Market value of property (in hundredths)

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

Reduced collateral value (in hundredths)

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

Percentage added to variable rate of interest (in hundredths)

'

'

'

'

2.25%

3.25%

'

'

'

'

'

'

'

'

'

Interest rate on credit facility (in hundredths)

'

'

2.67%

'

'

'

'

'

'

'

'

'

'

'

'

Description of variable rate basis

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Financial covenants, minimum current ratio

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Financial covenants, interest coverage ratio

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Financial covenants, total debt To EBITDAX ratio

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio

11.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total debt to EBITDAX ratio

0.76

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current ratio

1.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rig Loan Agreement [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Power of diesel electric drilling rig (in horsepower)

'

'

'

'

'

'

'

'

'

2,000

'

'

'

'

'

Amount that can be borrowed under rig loan agreement

'

'

'

'

'

'

7,000,000

'

'

'

'

'

'

'

'

Term of interest due on note

'

'

'

'

'

'

'18-months

'

'

'

'

'

'

'

'

Interest rate on debt (in hundredths)

'

'

'

'

'

'

4.26%

'

'

'

'

'

'

'

'

Real Estate Lien Note [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed interest rate on note (in hundredths)

'

'

'

'

'

'

'

'

'

'

4.25%

4.00%

'

'

'

Monthly installments of principal and interest

'

'

'

'

'

'

'

'

'

'

$34,354

$33,763

'

'

'

Debt Instrument, Basis Spread on Variable Rate, Expected Rate

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

Debt Instrument, Interest Rate, Effective Percentage Rate Range, Maximum Expected Rate

'

'

'

'

'

'

'

'

'

'

'

'

7.25%

'

'

Property_and_Equipment_Details

Property and Equipment (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]	'	'
Property and equipment	$603,714	$603,239
Oil and Gas Properties [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property and equipment	564,755	565,406
Equipment and Other [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property and equipment	17,237	19,052
Equipment and Other [Member] | Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful life	'3 years	'
Equipment and Other [Member] | Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful life	'39 years	'
Drilling Rig [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful life	'15 years	'
Property and equipment	$21,722	$18,781

Stockbased_Compensation_Option2

Stock-based Compensation, Option Plans and Warrants (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 30, 2012

Apr. 30, 2011

Apr. 30, 2010

Dec. 31, 2013

Dec. 31, 2012

$ 0.68 - 0.99 [Member]

$ 1.00 - 1.99 [Member]

$ 2.00 - 2.99 [Member]

$ 3.00 - 3.99 [Member]

$ 4.00 - 4.99 [Member]

$ 5.00 - 6.05 [Member]

Stock Options [Member]

Stock Options [Member]

Stock Options [Member]

Restricted Unit Awards [Member]

Restricted Unit Awards [Member]

Restricted Unit Awards [Member]

2005 Directors Plan [Member]

2005 Directors Plan [Member]

2005 Directors Plan [Member]

2005 Directors Plan [Member]

2005 Directors Plan [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-based compensation expense

$2,114,000

$2,091,000

$1,987,000

'

'

'

'

'

'

$1,700,000

$1,600,000

$1,500,000

$400,000

$500,000

$500,000

'

'

'

'

'

Weighted average assumptions used in fair value of the options [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average value per option granted during the period (in dollars per share)

'

'

'

'

'

'

'

'

'

$1.73

$2.17

$3.11

'

'

'

'

'

'

'

'

Assumptions [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected dividend yield (in hundredths)

'

'

'

'

'

'

'

'

'

0.00%

0.00%

0.00%

'

'

'

'

'

'

'

'

Volatility (in hundredths)

'

'

'

'

'

'

'

'

'

81.20%

81.40%

80.00%

'

'

'

'

'

'

'

'

Risk free interest rate (in hundredths)

'

'

'

'

'

'

'

'

'

1.24%

1.19%

2.21%

'

'

'

'

'

'

'

'

Expected life (years)

'

'

'

'

'

'

'

'

'

'6 years 6 months

'6 years 8 months 12 days

'6 years 4 months 24 days

'

'

'

'

'

'

'

'

Fair value of options granted

'

'

'

'

'

'

'

'

'

1,444,000

1,324,000

2,506,000

'

'

'

'

'

'

'

'

Authorized shares available for grant (in shares)

'

'

'

'

'

'

'

'

'

'

5,200,000

'

'

'

'

'

'

'

'

'

Options expiration period

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

Options [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Options outstanding, beginning balance (in shares)

'

'

'

'

'

'

'

'

'

4,761,000

4,756,000

4,820,000

'

'

'

'

'

'

'

'

Granted (in shares)

'

'

'

'

'

'

'

'

'

836,000

610,000

807,000

'

'

'

'

'

'

'

'

Exercised (in shares)

'

'

'

'

'

'

'

'

'

-166,000

-391,000

-530,000

'

'

'

'

'

'

'

'

Forfeited/Expired (in shares)

'

'

'

'

'

'

'

'

'

-31,000

-214,000

-341,000

'

'

'

'

'

'

'

'

Options outstanding, ending balance (in shares)

'

'

'

'

'

'

'

'

'

5,400,000

4,761,000

4,756,000

'

'

'

'

'

'

'

'

Exercisable at end of year (in shares)

'

'

'

'

'

'

'

'

'

3,828,000

'

'

'

'

'

'

'

'

'

'

Weighted average exercise price [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Options outstanding, beginning balance (in dollars per share)

'

'

'

'

'

'

'

'

'

$2.77

$2.61

$2.23

'

'

'

'

'

'

'

'

Granted (in dollars per share)

'

'

'

'

'

'

'

'

'

$2.43

$3.01

$4.37

'

'

'

'

'

'

'

'

Exercised (in dollars per share)

'

'

'

'

'

'

'

'

'

$1.18

$1.11

$1.54

'

'

'

'

'

'

'

'

Forfeited/Expired (in dollars per share)

'

'

'

'

'

'

'

'

'

$2.58

$2.80

$3.01

'

'

'

'

'

'

'

'

Options outstanding, ending balance (in dollars per share)

'

'

'

'

'

'

'

'

'

$2.77

$2.77

$2.61

'

'

'

'

'

'

'

'

Options outstanding weighted average exercise price of options exercisable

'

'

'

'

'

'

'

'

'

$1.93

'

'

'

'

'

'

'

'

'

'

Weighted average remaining life [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Options outstanding ending balance

'

'

'

'

'

'

'

'

'

'6 years 2 months 12 days

'

'

'

'

'

'

'

'

'

'

Exercisable at end of year

'

'

'

'

'

'

'

'

'

'5 years 3 months 18 days

'

'

'

'

'

'

'

'

'

'

Fair value per share [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Options outstanding, ending balance (in dollars per share)

'

'

'

'

'

'

'

'

'

$1.98

'

'

'

'

'

'

'

'

'

'

Exercisable at end of year, Fair value (in dollars per share)

'

'

'

'

'

'

'

'

'

$1.93

'

'

'

'

'

'

'

'

'

'

Other information pertaining to stock options activity [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average grant date fair value of stock options granted (in dollars per share)

'

'

'

'

'

'

'

'

'

$1.73

$2.17

$3.11

'

'

'

'

'

'

'

'

Total fair value of options vested

'

'

'

'

'

'

'

'

'

1,670,000

1,497,000

1,230,000

'

'

'

'

'

'

'

'

Total intrinsic value of options exercised

'

'

'

'

'

'

'

'

'

275,000

414,000

1,584,000

'

'

'

'

'

'

'

'

Compensation cost related to non-vested awards not yet recognized

'

'

'

'

'

'

'

'

'

2,200,000

'

'

'

'

'

'

'

'

'

'

Restricted Stock Awards [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Compensation cost not yet recognized

'

'

'

'

'

'

'

'

'

'

'

'

800,000

'

'

'

'

'

'

'

Number of Shares [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unvested, Beginning balance (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

482,025

629,771

400,295

'

'

'

'

'

Granted (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

48,222

89,860

408,676

'

'

'

'

'

Vested/Released (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

-169,700

-229,172

-156,890

'

'

'

'

'

Forfeited (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

-5,307

-8,434

-22,310

'

'

'

'

'

Unvested, Ending balance (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

355,240

482,025

629,771

'

'

'

'

'

Weighted average grant date fair value [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unvested, beginning balance (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

$3.09

$3.03

$2.02

'

'

'

'

'

Granted (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

$2.69

$2.12

$3.67

'

'

'

'

'

Vested/Released (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

$2.66

$2.57

$2.24

'

'

'

'

'

Forfeited (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

$3.08

$2.42

$2.27

'

'

'

'

'

Unvested, Ending balance (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

$3.24

$3.09

$3.03

'

'

'

'

'

Director Stock Awards [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares reserved for issuance (in shares)

'

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000

Number of shares to be granted for participation in board and committee meetings as per agreement (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,000

'

Maximum shares that can be awarded to one person (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000

'

Percentage of exercise price awarded (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

Annual retainer fee

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$40,000

$27,500

$26,000

'

'

Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock option plans exercise price range, lower range limit (in dollars per share)

'

'

'

$0.68

$1

$2

$3

$4

$5

'

'

'

'

'

'

'

'

'

'

'

Stock option plans exercise price range, upper limit (in dollars per share)

'

'

'

$0.99

$1.99

$2.99

$3.99

$4.99

$6.05

'

'

'

'

'

'

'

'

'

'

'

Options outstanding, Number (in shares)

5,400,210

'

'

627,450

1,114,672

1,670,025

745,563

1,168,500

74,000

'

'

'

'

'

'

'

'

'

'

'

Options outstanding, Weighted average remaining life

'

'

'

'5 years 2 months 16 days

'6 years 3 months 11 days

'7 years 7 months 28 days

'6 years 8 months 23 days

'4 years 5 months 19 days

'2 years 1 month 24 days

'

'

'

'

'

'

'

'

'

'

'

Options outstanding, Weighted average exercise price (in dollars per share)

'

'

'

$0.99

$1.75

$2.32

$3.64

$4.58

$6.05

'

'

'

'

'

'

'

'

'

'

'

Exercisable, Number (in shares)

3,827,724

'

'

627,450

964,672

816,925

399,427

945,250

74,000

'

'

'

'

'

'

'

'

'

'

'

Exercisable, Weighted average remaining life

'

'

'

'5 years 2 months 16 days

'5 years 10 months 28 days

'6 years 6 months 26 days

'5 years 5 months 27 days

'3 years 9 months 29 days

'2 years 1 month 24 days

'

'

'

'

'

'

'

'

'

'

'

Exercisable, Weighted average exercise price (in dollars per share)

'

'

'

$0.99

$1.71

$2.31

$3.62

$4.55

$6.05

'

'

'

'

'

'

'

'

'

'

'

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jul. 23, 2013
Deferred tax liabilities [Abstract]	'	'	'	'
Marketable securities	$0	$28,000	$36,000	'
Canada full cost pool	0	0	377,000	'
Investment in Blue Eagle	0	0	7,527,000	'
Hedge contracts	0	0	345,000	'
Deferred Tax Liabilities, Other	3,152,000	0	0	'
Total deferred tax liabilities	3,152,000	28,000	8,285,000	'
Deferred tax assets [Abstract]	'	'	'	'
U.S. full cost pool	11,725,000	13,837,000	29,976,000	'
Canada full cost pool	4,081,000	3,720,000	0	'
Depletion carryforward	4,743,000	4,930,000	4,842,000	'
U.S. net operating loss carryforward	49,667,000	59,362,000	52,564,000	'
Canada net operating loss carryforward	5,736,000	4,196,000	2,151,000	'
Alternative minimum tax credit	1,369,000	422,000	422,000	'
Hedge contracts	1,397,000	2,231,000	0	'
Other	0	1,042,000	1,811,000	'
Total deferred tax assets	78,718,000	89,740,000	91,766,000	'
Valuation allowance for deferred tax assets	-75,566,000	-89,712,000	-83,481,000	'
Net deferred tax assets	3,152,000	28,000	8,285,000	'
Net deferred tax	0	0	0	'
Current [Abstract]	'	'	'	'
Federal	632,000	310,000	-77,000	'
State	68,000	0	0	'
Foreign	0	0	0	'
Current provision (benefit) for income taxes	700,000	310,000	-77,000	'
Deferred [Abstract]	'	'	'	'
Federal	0	0	0	'
Foreign	0	0	0	'
Deferred provision (benefit) for income taxes	0	0	0	'
Operating Loss Carryforwards [Line Items]	'	'	'	'
Income taxes paid	'	'	'	391,000
Tax Adjustments, Settlements, and Unusual Provisions	81,000	'	'	'
Reconciliation of income tax computed at U.S federal statutory tax rates [Abstract]	'	'	'	'
Tax (expense) benefit at U.S. statutory rates (35%)	-13,771,000	6,468,000	-4,809,000	'
(Increase) decrease in deferred tax asset valuation allowance	14,146,000	-6,231,000	5,408,000	'
Rate differential for non U.S. income	-574,000	-1,533,000	-46,000	'
State income taxes	-47,000	0	0	'
Accrual of prior year federal taxes (2009)	-81,000	-310,000	0	'
Permanent differences	-743,000	-732,000	-533,000	'
Increase in asset for partnership distributions	0	1,945,000	0	'
Other	370,000	83,000	57,000	'
Income tax (expense) benefit	-700,000	-310,000	77,000	'
U.S statutory rate (in hundredths)	35.00%	'	'	'
Reduction in deferred tax assets	11,000,000	'	'	'
Tax adjustment assessed	619,000	310,000	'	'
U.S. Tax [Member]	'	'	'	'
Operating Loss Carryforwards [Line Items]	'	'	'	'
Net operating loss carryforwards	141,900,000	'	'	'
Expiration dates of operating loss carryforwards	'2033	'	'	'
Canadian Tax [Member]	'	'	'	'
Operating Loss Carryforwards [Line Items]	'	'	'	'
Net operating loss carryforwards	$20,500,000	'	'	'
Expiration dates of operating loss carryforwards	'2033	'	'	'

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Office Space in Calgary, Alberta [Member]	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Rent expense	$107,619	$112,276	$121,500
Office Space in Dickinson, North Dakota [Member]	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Rent expense	26,073	23,800	9,250
Office Space in Lusk, Wyoming [Member]	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Rent expense	$9,000	$9,000	$9,000

Earnings_per_Share_Details

Earnings per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except 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
Numerator [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Net income (loss)	$26,996	$3,190	$7,866	$595	($11,867)	($18,644)	$10,903	$817	$38,647	($18,791)	$13,743
Denominator [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Denominator for basic earnings per share - weighted-average common shares outstanding (in shares)	'	'	'	'	'	'	'	'	92,451,000	91,914,000	90,151,000
Effect of dilutive securities [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Stock options, restricted shares and warrants (in shares)	'	'	'	'	'	'	'	'	1,087,000	0	2,093,000
Dilutive potential common shares [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and warrants (in shares)	'	'	'	'	'	'	'	'	93,538,000	91,914,000	92,244,000
Net income (loss) per common share - basic (in dollars per share)	$0.29	$0.03	$0.09	$0.01	($0.13)	($0.20)	$0.12	$0.01	$0.42	($0.20)	$0.15
Net income (loss) per common share - diluted (in dollars per share)	$0.29	$0.03	$0.08	$0.01	($0.13)	($0.20)	$0.12	$0.01	$0.41	($0.20)	$0.15
Stock options excluded from the calculation of diluted income (loss) per share (in shares)	'	'	'	'	'	'	'	'	0	1,349	0

Quarterly_Results_of_Operation2

Quarterly Results of Operations (Unaudited) (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
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Net revenue	$22,546	$29,095	$21,494	$21,196	$19,069	$17,170	$15,938	$16,396	$94,331	$68,573	$64,622
Operating income (loss)	-2,869	11,161	2,867	3,768	-7,190	-11,359	-23	2,224	14,927	-16,348	11,648
Net income (loss)	$26,996	$3,190	$7,866	$595	($11,867)	($18,644)	$10,903	$817	$38,647	($18,791)	$13,743
Net income (loss) per common share - basic (in dollars per share)	$0.29	$0.03	$0.09	$0.01	($0.13)	($0.20)	$0.12	$0.01	$0.42	($0.20)	$0.15
Net income (loss) - per common share - diluted (in dollars per share)	$0.29	$0.03	$0.08	$0.01	($0.13)	($0.20)	$0.12	$0.01	$0.41	($0.20)	$0.15

Benefit_Plans_Details

Benefit Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Compensation and Retirement Disclosure [Abstract]	'	'	'
Contribution to 401(k) plan	$284,865	$267,289	$226,377
Percentage eligible pay for dollar by dollar fixed match (in hundredths)	1.00%	'	'
Employer contribution for each dollar contributed by employee after 1% of eligible pay	0.5	'	'
Maximum percentage of employee gross pay employer can contribute under 401(k) plan (in hundredths)	5.00%	'	'
Employee contribution limit for employees under 50 years of age	17,500	17,000	16,500
Employee contribution limit for employees of 50 years of age or older	$23,000	$22,500	$22,000

Business_Segments_Details

Business Segments (Details) (USD $)	3 Months Ended								12 Months Ended
	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
									segment	customer	customer
									customer
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Number of operating segments	'	'	'	'	'	'	'	'	1	'	'
Entity wide revenue, number of major customers	'	'	'	'	'	'	'	'	3	4	3
Entity wide revenue major customers (in hundredths)	'	'	'	'	'	'	'	'	50.00%	31.00%	28.00%
Revenues:	'	'	'	'	'	'	'	'	'	'	'
Oil and gas production	'	'	'	'	'	'	'	'	$94,275,000	$68,499,000	$64,615,000
Other	'	'	'	'	'	'	'	'	56,000	74,000	7,000
Total revenue	22,546,000	29,095,000	21,494,000	21,196,000	19,069,000	17,170,000	15,938,000	16,396,000	94,331,000	68,573,000	64,622,000
Costs and expenses [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Lease operating	'	'	'	'	'	'	'	'	25,361,000	24,806,000	21,581,000
Production taxes	'	'	'	'	'	'	'	'	8,510,000	6,613,000	5,766,000
Depreciation, depletion, and amortization	'	'	'	'	'	'	'	'	26,632,000	23,016,000	16,194,000
Impairment	'	'	'	'	'	'	'	'	6,025,000	19,774,000	0
General and administrative	'	'	'	'	'	'	'	'	12,876,000	10,712,000	9,433,000
Net interest	'	'	'	'	'	'	'	'	4,577,000	5,516,000	4,891,000
Amortization of deferred financing fees	'	'	'	'	'	'	'	'	1,367,000	937,000	1,762,000
Gain on sale of properties	'	'	'	'	'	'	'	'	-33,377,000	'	'
Gain (Loss) on Sale of Derivatives	'	'	'	'	'	'	'	'	5,035,000	459,000	676,000
Gain on derivative contracts - unrealized	'	'	'	'	'	'	'	'	-2,561,000	-2,669,000	-7,476,000
Earnings from equity method investment	'	'	'	'	'	'	'	'	0	-2,207,000	-2,187,000
Income tax	'	'	'	'	'	'	'	'	700,000	310,000	-77,000
Other	'	'	'	'	'	'	'	'	539,000	97,000	316,000
Net income (loss)	26,996,000	3,190,000	7,866,000	595,000	-11,867,000	-18,644,000	10,903,000	817,000	38,647,000	-18,791,000	13,743,000
Segment Assets [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Total assets	223,650,000	'	'	'	240,607,000	'	'	'	223,650,000	240,607,000	'
U.S. [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Entity wide revenue, number of major customers	'	'	'	'	'	'	'	'	2	3	2
Entity wide revenue major customers (in hundredths)	'	'	'	'	'	'	'	'	49.00%	28.00%	26.00%
Revenues:	'	'	'	'	'	'	'	'	'	'	'
Oil and gas production	'	'	'	'	'	'	'	'	92,268,000	65,590,000	63,105,000
Other	'	'	'	'	'	'	'	'	0	0	0
Total revenue	'	'	'	'	'	'	'	'	92,268,000	65,590,000	63,105,000
Costs and expenses [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Lease operating	'	'	'	'	'	'	'	'	23,205,000	22,578,000	20,788,000
Production taxes	'	'	'	'	'	'	'	'	8,437,000	6,588,000	5,764,000
Depreciation, depletion, and amortization	'	'	'	'	'	'	'	'	25,338,000	20,704,000	15,236,000
Impairment	'	'	'	'	'	'	'	'	0	0	0
General and administrative	'	'	'	'	'	'	'	'	2,471,000	1,980,000	1,698,000
Net interest	'	'	'	'	'	'	'	'	615,000	457,000	448,000
Amortization of deferred financing fees	'	'	'	'	'	'	'	'	0	0	0
Gain on sale of properties	'	'	'	'	'	'	'	'	0	'	'
Gain (Loss) on Sale of Derivatives	'	'	'	'	'	'	'	'	0	0	0
Gain on derivative contracts - unrealized	'	'	'	'	'	'	'	'	0	0	0
Earnings from equity method investment	'	'	'	'	'	'	'	'	'	0	0
Income tax	'	'	'	'	'	'	'	'	0	0	0
Other	'	'	'	'	'	'	'	'	0	0	0
Net income (loss)	'	'	'	'	'	'	'	'	32,202,000	13,283,000	19,171,000
Segment Assets [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Total assets	213,212,000	'	'	'	223,253,000	'	'	'	213,212,000	223,253,000	'
Canada [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Entity wide revenue, number of major customers	'	'	'	'	'	'	'	'	1	1	1
Entity wide revenue major customers (in hundredths)	'	'	'	'	'	'	'	'	100.00%	100.00%	100.00%
Revenues:	'	'	'	'	'	'	'	'	'	'	'
Oil and gas production	'	'	'	'	'	'	'	'	2,007,000	2,909,000	1,510,000
Other	'	'	'	'	'	'	'	'	0	0	0
Total revenue	'	'	'	'	'	'	'	'	2,007,000	2,909,000	1,510,000
Costs and expenses [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Lease operating	'	'	'	'	'	'	'	'	2,156,000	2,228,000	793,000
Production taxes	'	'	'	'	'	'	'	'	73,000	25,000	2,000
Depreciation, depletion, and amortization	'	'	'	'	'	'	'	'	1,045,000	2,063,000	709,000
Impairment	'	'	'	'	'	'	'	'	6,025,000	19,774,000	0
General and administrative	'	'	'	'	'	'	'	'	879,000	699,000	654,000
Net interest	'	'	'	'	'	'	'	'	23,000	17,000	4,000
Amortization of deferred financing fees	'	'	'	'	'	'	'	'	0	0	0
Gain on sale of properties	'	'	'	'	'	'	'	'	0	'	'
Gain (Loss) on Sale of Derivatives	'	'	'	'	'	'	'	'	0	0	0
Gain on derivative contracts - unrealized	'	'	'	'	'	'	'	'	0	0	0
Earnings from equity method investment	'	'	'	'	'	'	'	'	'	0	0
Income tax	'	'	'	'	'	'	'	'	0	0	0
Other	'	'	'	'	'	'	'	'	0	0	0
Net income (loss)	'	'	'	'	'	'	'	'	-8,194,000	-21,897,000	-652,000
Segment Assets [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Total assets	1,640,000	'	'	'	7,053,000	'	'	'	1,640,000	7,053,000	'
Corporate [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenues:	'	'	'	'	'	'	'	'	'	'	'
Oil and gas production	'	'	'	'	'	'	'	'	0	0	0
Other	'	'	'	'	'	'	'	'	56,000	74,000	7,000
Total revenue	'	'	'	'	'	'	'	'	56,000	74,000	7,000
Costs and expenses [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Lease operating	'	'	'	'	'	'	'	'	0	0	0
Production taxes	'	'	'	'	'	'	'	'	0	0	0
Depreciation, depletion, and amortization	'	'	'	'	'	'	'	'	249,000	249,000	249,000
Impairment	'	'	'	'	'	'	'	'	0	0	0
General and administrative	'	'	'	'	'	'	'	'	9,526,000	8,033,000	7,081,000
Net interest	'	'	'	'	'	'	'	'	3,939,000	5,042,000	4,439,000
Amortization of deferred financing fees	'	'	'	'	'	'	'	'	1,367,000	937,000	1,762,000
Gain on sale of properties	'	'	'	'	'	'	'	'	-33,377,000	'	'
Gain (Loss) on Sale of Derivatives	'	'	'	'	'	'	'	'	5,035,000	459,000	676,000
Gain on derivative contracts - unrealized	'	'	'	'	'	'	'	'	-2,561,000	-2,669,000	-7,476,000
Earnings from equity method investment	'	'	'	'	'	'	'	'	'	-2,207,000	-2,187,000
Income tax	'	'	'	'	'	'	'	'	700,000	310,000	-77,000
Other	'	'	'	'	'	'	'	'	539,000	97,000	316,000
Net income (loss)	'	'	'	'	'	'	'	'	14,639,000	-10,177,000	-4,776,000
Segment Assets [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Total assets	$8,798,000	'	'	'	$10,301,000	'	'	'	$8,798,000	$10,301,000	'

Hedging_Program_and_Derivative2

Hedging Program and Derivatives (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 17, 2014

Mar. 17, 2014

In Thousands, unless otherwise specified

Commodity Price Derivatives [Member]

Commodity Price Derivatives [Member]

Commodity Price Derivatives [Member]

Commodity Price Derivatives [Member]

Commodity Price Derivatives [Member]

Commodity Price Derivatives [Member]

Commodity Price Derivatives [Member]

Commodity Price Derivatives [Member]

Oil - WTI [Member]

Oil - WTI [Member]

Oil - WTI [Member]

Oil - WTI [Member]

Oil - Brent [Member]

Oil - Brent [Member]

Oil - Brent [Member]

Oil - Brent [Member]

Oil - LLS [Member]

Oil - LLS [Member]

Oil - LLS [Member]

Oil - LLS [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Derivative Asset - Current [Member]

Derivative Asset - Current [Member]

Derivative Asset - Long-Term [Member]

Derivative Asset - Long-Term [Member]

Derivative Liability - Current [Member]

Derivative Liability - Current [Member]

Derivative Liability - Long-Term [Member]

Derivative Liability - Long-Term [Member]

2014 [Member]

2015 [Member]

2016 [Member]

2017 [Member]

2014 [Member]

2015 [Member]

2016 [Member]

2017 [Member]

2014 [Member]

2015 [Member]

2016 [Member]

2017 [Member]

Natural Gas [Member]

Natural Gas [Member]

bbl

bbl

bbl

bbl

bbl

bbl

bbl

bbl

bbl

bbl

bbl

bbl

2014 [Member]

2015 [Member]

Mcf

Mcf

Oil and Gas Delivery Commitments and Contracts [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Daily Volume (in Bbl)

'

'

'

'

'

'

'

'

'

'

687

560

963

500

505

500

0

0

100

0

0

0

1,597

1,450

Swap Price (in dollars per Bbl)

'

'

'

'

'

'

'

'

'

'

94.16

83.03

84.1

84.18

100.56

97.04

0

0

101.26

0

0

0

4.1

4.22

Impact of derivative contracts on balance sheet [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative asset - current

$85

$41

$85

$41

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative asset - long-term

925

594

'

'

925

594

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Assets

1,010

635

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative liability - current

2,728

3,462

'

'

'

'

2,728

3,462

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative liability - long-term

2,274

3,568

'

'

'

'

'

'

2,274

3,568

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Liabilities

$5,002

$7,030

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Financial_Instruments_Details

Financial Instruments (Details)

0 Months Ended

Aug. 12, 2013

6-May-13

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

USD ($)

CAD

USD ($)

USD ($)

Recurring Basis [Member]

Recurring Basis [Member]

Recurring Basis [Member]

Recurring Basis [Member]

Recurring Basis [Member]

Recurring Basis [Member]

Recurring Basis [Member]

Recurring Basis [Member]

USD ($)

USD ($)

Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]

Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]

Significant Other Observable Inputs (Level 2) [Member]

Significant Other Observable Inputs (Level 2) [Member]

Significant Unobservable Inputs (Level 3) [Member]

Significant Unobservable Inputs (Level 3) [Member]

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Share Price

'

1.35

'

'

'

'

'

'

'

'

'

'

Assets [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

Investment in common stock

'

'

'

'

'

$78,000

'

$78,000

'

$0

'

$0

NYMEX Fixed Price Derivative contracts

'

'

1,010,000

635,000

1,010,000

635,000

0

0

1,010,000

635,000

0

0

Total Assets

'

'

'

'

1,010,000

713,000

0

78,000

1,010,000

635,000

0

0

Liabilities [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

NYMEX Fixed Price Derivative contracts

'

'

'

'

5,002,000

7,030,000

0

0

5,002,000

7,030,000

0

0

Total Liabilities

'

'

'

'

5,002,000

7,030,000

0

0

5,002,000

7,030,000

0

0

Proceeds from (Repurchase of) Equity

$133,592

'

'

'

'

'

'

'

'

'

'

'

Supplemental_Oil_and_Gas_Discl2

Supplemental Oil and Gas Disclosures (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized costs relating to oil and gas producing activities [Abstract]	'	'	'
Proved oil and gas properties	$564,755	$563,317	'
Unproved properties	0	2,089	'
Total	564,755	565,406	'
Accumulated depreciation, depletion, amortization and impairment	-413,704	-383,469	'
Net capitalized costs	151,051	181,937	'
Cost incurred in oil and gas property acquisition and development activities [Abstract]	'	'	'
Development costs	93,878	56,318	46,735
Exploration costs	0	0	8,410
Property acquisition costs	0	7,200	0
Unproved	0	989	1,100
Total	93,878	64,507	56,245
Results of operations for oil and gas producing activities [Abstract]	'	'	'
Revenues	94,275	68,499	64,615
Production costs	-33,871	-31,419	-27,347
Depreciation, depletion, and amortization	-26,072	-22,767	-15,595
Proved property impairment	-6,025	-19,774	0
General and administrative	-3,350	-2,679	-2,352
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	24,957	-8,140	19,321
Depletion per barrel of oil equivalent	16.59	15.59	12.26
Oil/NGL [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	19,956,000	14,219,000	9,794,000
Revisions of previous estimates	999,000	1,574,000	2,290,000
Extensions and discoveries	10,746,000	5,809,000	2,703,000
Purchases of minerals in place	0	1,000	'
Sales of minerals in place	-7,748,000	-850,000	0
Production	1,000,000	797,000	568,000
Balance	22,953,000	19,956,000	14,219,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	8,310,000	8,650,000	7,761,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	14,640,000	11,306,000	6,460,000
Natural Gas [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	61,184,000	72,075,000	84,913,000
Revisions of previous estimates	-5,123,000	-7,470,000	-13,009,000
Extensions and discoveries	3,610,000	6,983,000	4,393,000
Purchases of minerals in place	0	69,000	'
Sales of minerals in place	-8,141,000	-6,376,000	0
Production	3,421,000	4,097,000	4,222,000
Balance	48,109,000	61,184,000	72,075,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	31,572,000	41,220,000	42,582,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	16,537,000	19,964,000	29,493,000
Oil Equivalents [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	30,152,000	26,232,000	23,947,000
Revisions of previous estimates	145,000	328,000	122,000
Extensions and discoveries	11,348,000	6,973,000	3,435,000
Purchases of minerals in place	0	13,000	'
Sales of minerals in place	-9,105,000	-1,913,000	0
Production	1,570,000	1,481,000	1,272,000
Balance	30,970,000	30,152,000	26,232,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	13,572,000	15,520,000	14,858,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	17,397,000	14,634,000	11,376,000
U.S. [Member]	'	'	'
Capitalized costs relating to oil and gas producing activities [Abstract]	'	'	'
Proved oil and gas properties	530,996	531,971	'
Unproved properties	0	0	'
Total	530,996	531,971	'
Accumulated depreciation, depletion, amortization and impairment	-381,283	-356,255	'
Net capitalized costs	149,713	175,716	'
Cost incurred in oil and gas property acquisition and development activities [Abstract]	'	'	'
Development costs	91,325	48,283	32,471
Exploration costs	0	0	8,410
Property acquisition costs	0	7,200	0
Unproved	0	0	0
Total	91,325	55,483	40,881
Results of operations for oil and gas producing activities [Abstract]	'	'	'
Revenues	92,268	65,590	63,105
Production costs	-31,642	-29,166	-26,552
Depreciation, depletion, and amortization	-25,028	-20,704	-14,914
Proved property impairment	0	0	0
General and administrative	-2,471	-1,980	-1,698
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	33,127	13,740	19,941
Depletion per barrel of oil equivalent	16.32	14.74	11.96
U.S. [Member] | Oil/NGL [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	19,751,000	13,780,000	9,718,000
Revisions of previous estimates	1,073,000	1,774,000	2,290,000
Extensions and discoveries	10,746,000	5,809,000	2,326,000
Purchases of minerals in place	0	1,000	'
Sales of minerals in place	-7,748,000	-850,000	0
Production	976,000	763,000	554,000
Balance	22,846,000	19,751,000	13,780,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	8,284,000	8,531,000	7,433,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	14,560,000	11,220,000	6,348,000
U.S. [Member] | Natural Gas [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	60,099,000	69,191,000	84,523,000
Revisions of previous estimates	-4,804,000	-5,786,000	-13,009,000
Extensions and discoveries	3,610,000	6,983,000	1,837,000
Purchases of minerals in place	0	69,000	'
Sales of minerals in place	-8,141,000	-6,376,000	0
Production	3,343,000	3,982,000	4,160,000
Balance	47,421,000	60,099,000	69,191,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	31,424,000	40,723,000	40,451,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	15,996,000	19,376,000	28,740,000
U.S. [Member] | Oil Equivalents [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	29,768,000	25,313,000	23,806,000
Revisions of previous estimates	270,000	809,000	122,000
Extensions and discoveries	11,348,000	6,973,000	2,632,000
Purchases of minerals in place	0	13,000	'
Sales of minerals in place	-9,105,000	-1,913,000	0
Production	1,533,000	1,427,000	1,247,000
Balance	30,748,000	29,768,000	25,313,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	13,521,000	15,318,000	14,175,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	17,226,000	14,450,000	11,138,000
Canada [Member]	'	'	'
Capitalized costs relating to oil and gas producing activities [Abstract]	'	'	'
Proved oil and gas properties	33,759	31,346	'
Unproved properties	0	2,089	'
Total	33,759	33,435	'
Accumulated depreciation, depletion, amortization and impairment	-32,421	-27,214	'
Net capitalized costs	1,338	6,221	'
Cost incurred in oil and gas property acquisition and development activities [Abstract]	'	'	'
Development costs	2,553	8,035	14,264
Exploration costs	0	0	0
Property acquisition costs	0	0	0
Unproved	0	989	1,100
Total	2,553	9,024	15,364
Results of operations for oil and gas producing activities [Abstract]	'	'	'
Revenues	2,007	2,909	1,510
Production costs	-2,229	-2,253	-795
Depreciation, depletion, and amortization	-1,044	-2,063	-681
Proved property impairment	-6,025	-19,774	0
General and administrative	-879	-699	-654
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	($8,170)	($21,880)	($620)
Depletion per barrel of oil equivalent	27.37	37.48	27.58
Canada [Member] | Oil/NGL [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	205,000	439,000	76,000
Revisions of previous estimates	-74,000	-200,000	0
Extensions and discoveries	0	0	377,000
Purchases of minerals in place	0	0	'
Sales of minerals in place	0	0	0
Production	24,000	34,000	14,000
Balance	107,000	205,000	439,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	26,000	119,000	328,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	80,000	86,000	112,000
Canada [Member] | Natural Gas [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	1,085,000	2,884,000	390,000
Revisions of previous estimates	-319,000	-1,684,000	0
Extensions and discoveries	0	0	2,556,000
Purchases of minerals in place	0	0	'
Sales of minerals in place	0	0	0
Production	78,000	115,000	62,000
Balance	688,000	1,085,000	2,884,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	148,000	497,000	2,131,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	541,000	588,000	753,000
Canada [Member] | Oil Equivalents [Member]	'	'	'
Proved developed and undeveloped reserves [Abstract]	'	'	'
Balance	384,000	919,000	141,000
Revisions of previous estimates	-125,000	-481,000	0
Extensions and discoveries	0	0	803,000
Purchases of minerals in place	0	0	'
Sales of minerals in place	0	0	0
Production	37,000	54,000	25,000
Balance	222,000	384,000	919,000
Proved Developed Reserves [Abstract]	'	'	'
Proved Developed Reserves	51,000	202,000	683,000
Proved Undeveloped Reserves [Abstract]	'	'	'
Proved Undeveloped Reserves	171,000	184,000	238,000

Supplemental_Oil_and_Gas_Discl3

Supplemental Oil and Gas Disclosures (Unaudited), Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	people
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Period for standardize measure of discounted future net cash flows	'12 months		'		'
Number of years of experience of Evaluator	'35 years		'		'
Number of engineers	4		'		'
Discount rate (in hundredths)	10.00%		'		'
Future net cash inflows after income taxes discounted at 10% annual discount rate to arrive at Standardized Measure [Abstract]	'		'		'
Future cash inflows	$2,244,846		$1,784,920		$1,471,352
Future production costs	-754,722		-642,706		-544,970
Future development costs	-467,206		-328,554		-228,804
Future income tax expense	-244,394		-149,625		-106,839
Future net cash flows	778,524		664,035		590,739
Discount	-437,539		-385,890		-321,657
Standardized Measure of discounted future net cash relating to proved reserves	340,985		278,145		269,082
Analysis of the changes in Standardized Measure [Roll Forward]	'		'		'
Standardized Measure, beginning of year	278,145		269,082		196,993
Sales and transfers of oil and gas produced, net of production costs	60,403		37,080		37,171
Net change in prices and development and production costs from prior year	169,969		60,710		92,886
Extensions, discoveries, and improved recovery, less related costs	156,456		73,236		47,765
Sales of minerals in place	-125,533		-20,089		0
Purchased of minerals in place	0		131		0
Revisions of previous quantity estimates	2,930		3,355		1,329
Change in timing and other	-62,861		-88,309		-23,501
Change in future income tax expense	-45,532		-9,799		-28,918
Accretion of discount	27,814		26,908		19,699
Standardized Measure, end of year	340,985		278,145		269,082
Oil and gas prices considered in standardized measure of discounted future net cash flows [Abstract]	'		'		'
Oil (in dollars per Bbl)	97.33	[1]	95.14	[1]	96.19	[1]
Gas (in dollars per MMbtu)	3.67	[2]	2.86	[2]	4.16	[2]
Oil (in dollars per Bbl)	95.9	[3]	88.26	[3]	88.58	[3]
Gas (in dollars per MMBtu)	3.65	[4]	2.61	[4]	3.73	[4]
NGL's (in dollars per Bbl)	31.98	[5]	36.76	[5]	50.21	[5]
U.S. [Member]	'		'		'
Future net cash inflows after income taxes discounted at 10% annual discount rate to arrive at Standardized Measure [Abstract]	'		'		'
Future cash inflows	2,234,632		1,766,515		1,420,013
Future production costs	-751,058		-634,903		-532,056
Future development costs	-463,456		-324,704		-224,254
Future income tax expense	-244,394		-149,625		-104,279
Future net cash flows	775,724		657,283		559,424
Discount	-436,077		-383,271		-310,516
Standardized Measure of discounted future net cash relating to proved reserves	339,647		274,012		248,908
Canada [Member]	'		'		'
Future net cash inflows after income taxes discounted at 10% annual discount rate to arrive at Standardized Measure [Abstract]	'		'		'
Future cash inflows	10,214		18,405		51,339
Future production costs	-3,664		-7,803		-12,914
Future development costs	-3,750		-3,850		-4,550
Future income tax expense	0		0		-2,560
Future net cash flows	2,800		6,752		31,315
Discount	-1,462		-2,619		-11,141
Standardized Measure of discounted future net cash relating to proved reserves	$1,338		$4,133		$20,174
[1]	The quoted oil price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2011, 2012 and 2013.
[2]	The quoted gas price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2011, 2012 and 2013.
[3]	The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
[4]	The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
[5]	The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.