Abraxas Petroleum (AXAS) 10-K 13 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 12, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	ABRAXAS PETROLEUM CORP
Entity Central Index Key	867665
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		106,191,078
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$604,088,667

CONSOLIDATED_BALANCE_SHEET

CONSOLIDATED BALANCE SHEET (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$3,772	$5,205
Accounts receivable:
Joint owners	5,648	15,493
Oil and gas production sales	15,308	16,625
Other	647	1,497
Total accounts receivable	21,603	33,615
Derivative asset	12,214	85
Other current assets	843	644
Total current assets	38,432	39,549
Oil and gas properties, full cost method of accounting:
Proved	716,922	564,755
Other property and equipment	40,683	38,959
Total	757,605	603,714
Less accumulated depreciation, depletion, and amortization	-434,726	-423,069
Total property and equipment, net	322,879	180,645
Deferred financing fees, net	2,216	2,140
Derivative asset	10,981	925
Other assets	391	391
Total assets	374,899	223,650
Current liabilities:
Accounts payable	63,549	52,793
Joint interest oil and gas production payable	14,423	23,810
Accrued interest	72	31
Other accrued expenses	1,006	1,231
Derivative liability	13	2,728
Current maturities of long-term debt	2,235	2,142
Total current liabilities	81,298	82,735
Long-term debt – less current maturities	76,554	41,790
Other liabilities	57	57
Derivative liability	0	2,274
Future site restoration	9,495	9,888
Total liabilities	167,404	136,744
Stockholders’ Equity:
Preferred stock, par value $.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding
Common stock, par value $.01 per share – authorized 200,000,000 shares; issued and outstanding 92,906,049 and 106,186,678	1,062	929
Additional paid-in capital	309,773	253,193
Accumulated deficit	-103,340	-166,609
Accumulated other comprehensive (loss)	0	-607
Total stockholders’ equity	207,495	86,906
Total liabilities and stockholders’ equity	$374,899	$223,650

CONSOLIDATED_BALANCE_SHEET_Par

CONSOLIDATED BALANCE SHEET (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
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)	106,186,678	92,906,049
Common stock, shares outstanding (in shares)	106,186,678	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil and gas production revenues	$133,701	$92,268	$65,590
Other	75	56	74
Total revenue	133,776	92,324	65,664
Operating costs and expenses:
Lease operating	25,875	23,205	22,578
Production taxes	11,462	8,437	6,588
Depreciation, depletion, and amortization	43,139	25,588	20,953
General and administrative (including stock-based compensation of $2,091, $2,114 and $2,703, respectively)	13,378	11,997	10,013
Operating expenses	93,854	69,227	60,132
Operating income	39,922	23,097	5,532
Other (income) expense:
Interest income	-2	-3	-4
Interest expense	2,570	4,556	5,503
Amortization of deferred financing fees	934	1,367	937
Gain on sale of properties	0	-33,377	0
Loss (gain) on derivative contracts - realized	-361	5,035	459
Gain on derivative contracts - unrealized	-24,876	-2,561	-2,669
Earnings from equity method investment	0	0	-2,207
Other	-7	539	97
Total other (income) expense	-21,742	-24,444	2,116
Income from continuing operations before income tax	61,664	47,541	3,416
Income tax (expense) benefit	287	-700	-310
Net income from continuing operations	61,951	46,841	3,106
Net (loss) income from discontinued operations - net of tax	1,318	-8,194	-21,897
Net income (loss)	$63,269	$38,647	($18,791)
Net income (loss) per common share - basic
Continuing operations (in dollars per share)	$0.63	$0.51	$0.04
Discontinued operations (in dollars per share)	$0.01	($0.09)	($0.24)
Total (in dollars per share)	$0.64	$0.42	($0.20)
Net income (loss) per common share - diluted
Continuing operations (in dollars per share)	$0.61	$0.50	$0.04
Discontinued operations (in dollars per share)	$0.01	($0.09)	($0.24)
Total (in dollars per share)	$0.62	$0.41	($0.20)

CONSOLIDATED_STATEMENTS_OF_OPE1

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating costs and expenses:
Stock-based compensation	$2,703	$2,114	$2,091

CONSOLIDATED_STATEMENTS_OF_OTH

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Consolidated net income (loss)	$63,269	$38,647	($18,791)
Other comprehensive income (loss):
Change in unrealized value of investments	0	-79	-25
Foreign currency translation adjustment	607	-559	343
Other comprehensive income (loss)	607	-638	318
Comprehensive income (loss)	$63,876	$38,009	($18,473)

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, 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	-18,791,000	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		92,733,448
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	92,906,049	92,906,049
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	63,269,000	0	0		0
Change in unrealized gain (loss) on fair value of investments	0
Foreign currency translation adjustment	607,000	0	0	0	607,000
Stock-based compensation	2,703,000	0	2,703,000	0	0
Stock options exercised	255,000	3,000	252,000	0	0
Stock options exercised (in shares)		238,157
Restricted stock issued, net of cancellations	0	15,000	-15,000	0	0
Restricted stock issued, net of cancellations (in shares)		1,542,472
Balance at Dec. 31, 2014	$207,495,000	$1,062,000	$309,773,000	($103,340,000)	$0
Balance (in shares) at Dec. 31, 2014	106,186,678	106,186,678

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Activities
Net income (loss)	$63,269	$38,647	($18,791)
Net (loss) income from discontinued operations	1,318	-8,194	-21,897
Net income from continuing operations	61,951	46,841	3,106
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Earnings from equity method investment	0	0	-2,207
Gain on sale of properties	0	-33,377	0
Change in derivative fair value	-27,326	-2,403	-4,088
Monetization of derivative contracts	152	0	12,364
Depreciation, depletion, and amortization	43,139	25,588	20,953
Accretion of future site restoration	559	615	457
Amortization of deferred financing fees	934	1,367	937
Stock-based compensation	2,703	2,114	2,091
Changes in operating assets and liabilities:
Accounts receivable	11,881	-13,702	-7,703
Other assets and liabilities	-267	-145	269
Accounts payable	1,596	27,514	26,264
Accrued expenses	-860	-1,933	2,930
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	94,462	52,479	55,373
Cash Provided by (Used in) Operating Activities, Discontinued Operations	1,741	-825	-3,998
Net cash provided by continuing operations	96,203	51,654	51,375
Investing Activities
Capital expenditures, including purchases and development of properties	-192,799	-92,489	-59,528
Proceeds from the sale of oil and gas properties	5,999	127,529	21,549
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	-186,800	35,040	-37,979
Cash Provided by (Used in) Investing Activities, Discontinued Operations	332	-2,554	-9,024
Net cash (used in) provided by continuing operations	-186,468	32,486	-47,003
Financing Activities
Proceeds from exercise of stock options	255	83	431
Proceeds from issuance of common stock, net of offering costs	53,755	0	0
Proceeds from long-term borrowings	82,000	42,000	30,500
Payments on long-term borrowings	-47,143	-122,826	-32,181
Deferred financing fees	-1,010	-110	-844
Other	0	-3,536	-13,239
Net Cash Provided by (Used in) Financing Activities, Continuing Operations	87,857	-84,389	-15,333
Cash Provided by (Used in) Financing Activities, Discontinued Operations	975	3,375	13,022
Net cash (used in) provided by continuing operations	88,832	-81,014	-2,311
Effect of exchange rate changes on cash - discontinued operations	0	18	0
Increase (decrease) in cash	-1,433	3,144	2,061
Cash at beginning of year	5,205	2,061	0
Cash at end of year	3,772	5,205	2,061
Supplemental disclosure of cash flow information:
Interest Paid	1,970	3,986	5,180
Income taxes paid	0	391	0
Non-Cash Investing Activities:
Asset retirement obligation cost and liabilities	-198	-138	-2,588
Non-cash transfer of investment in joint venture	0	0	-28,531
Asset retirement obligations associated with property acquisitions and dispositions	($406)	($1,890)	$324

Organization_and_Significant_A

Organization and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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.  Our oil and gas assets are located in three operating regions in the United States, the Rocky Mountain, Permian Basin and onshore Gulf Coast.
	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”).
	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.
	Reclassification of prior period balances
	Certain amounts in the prior periods presented have been reclassified to conform to the current year financial statement presentation. These reclassifications have no effect on previously reported net income.
	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 $407,000 at December 31, 2013 and 2014. 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, 2012, 2013 and 2014, our net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves.
	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, 2013 and 2014, and costs as of December 31, 2013 and 2014. 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 (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, 2012, 2013 and 2014, stock-based compensation was approximately $2.1 million, $2.1 million and $2.7 million, respectively. For additional information regarding share-based payments, refer to Note 6, “Stock-Based Compensation and Option Plans.”
	Restoration, Removal and Environmental Liabilities
	The Company is subject to extensive federal, 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:
			2013			2014
		(in thousands)
	Beginning asset retirement obligation		$	11,381		$	9,888
	New wells placed on production and other		183			444
	Deletions related to property disposals and plugging costs		(2,491		)	(1,318		)
	Accretion expense		615			559
	Revisions		151			198
	Discontinued operations		49			(276		)
	Ending asset retirement obligation		$	9,888		$	9,495
	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, 2013 and 2014.
	During 2012, three purchasers accounted for 39% of oil and gas revenues. During 2013, two purchasers accounted for 49% of oil and gas revenues. During 2014, two customers accounted for 62% 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 $60.1 million for deferred tax assets at December 31, 2014.
	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. During the year ended December 31, 2014, other comprehensive income of $0.6 million representing translation adjustments for the Company’s former Canadian operations were reflected in net income from discontinued operations. There is no accumulated other comprehensive income as of December 31, 2014.
New Accounting Standards and Disclosures
Revenue Recognition
The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014 which provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. The requirements from the new ASU are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. At this time, we are evaluating the guidance to determine the method of adoption and the impact of this ASU on our financial statements and related disclosures, if any.

Joint_Venture

Joint Venture	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Joint Venture	Joint Venture
	From August 18, 2010 through August 31, 2012, Abraxas Petroleum and its wholly-owned subsidiary, Abraxas Operating, LLC, owned an equity interest in the joint venture, Blue Eagle Energy, LLC (“Blue Eagle”). 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 year ended 2012 through the date of dissolution we reported income of $2.2 million, related to Blue Eagle.
	The following is condensed financial data from Blue Eagle’s August 31, 2012 (date of dissolution) financial statements:
			Year Ended
			December 31,
	Statement of Operations:		2012 (1)
		(in thousands)
	Revenue		$	12,106
	Operating expenses		7,144
	Other income		(4		)
	Net income		$	4,966
	(1) Through August 31, 2012

Divestiture_of_NonCore_Propert

Divestiture of Non-Core Properties	12 Months Ended
	Dec. 31, 2014
Divestiture of Non Core Properties [Abstract]
Divestiture of Non-Core Properties	Divestiture of Properties
	Beginning in the third quarter of 2012 and continuing throughout 2014, 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 2013 netted $0.6 million. In the first quarter of 2014 we sold several non-core Permian Basin and Gulf Coast properties for combined proceeds of $2.6 million. In the second quarter of 2014 we sold a non-core Permian Basin property for net proceeds of $2.5 million. Other non-core asset sales during 2014 netted $0.9 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 in 2013.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt
	The following is a description of the Company’s debt as of December 31, 2013 and 2014, respectively:
			December 31,			December 31,
			2013			2014
			(In thousands)
	Senior secured credit facility		$	33,000		$	70,000
	Rig loan agreement		6,378			4,456
	Real estate lien note		4,554			4,333
			43,932			78,789
	Less current maturities		(2,142		)	(2,235		)
			$	41,790		$	76,554
	Maturities of long-term debt are as follows:
	Year ending December 31, (In thousands)
	2015	$	2,235
	2016	2,333
	2017	608
	2018	70,262
	2019	273
	Thereafter	3,078
		$	78,789
	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, 2014, $70.0 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, 2014, we had a borrowing base of $165.0 million. 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) 0.75%—1.75%, depending on the utilization of the borrowing base, or, if we elect LIBOR plus 1.75%—2.75%, depending on the utilization of the borrowing base. At December 31, 2014, the interest rate on the credit facility was 2.16% 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, 2018. 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 plus expenses incurred in connection with the negotiation, execution, delivery and performance of the Credit Facility plus expenses incurred in connection with any acquisition permitted under the Credit Facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses 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, 2014 we were in compliance with all of our debt covenants. As of December 31, 2014, the interest coverage ratio was 42.81 to 1.00, the total debt to EBITDAX ratio was 0.82 to 1.00, and our current ratio was 1.53 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, secured by our Oilwell 2000 HP diesel electric drilling rig (the “Collateral”). The original principal amount of the note was $7.0 million and bears interest at 4.26%.  The note is payable in monthly interest and principal payments in the amount of $179,695. Subject to earlier prepayment provisions and events of default, the stated maturity date of the note is February 14, 2017. As of December 31, 2013 and 2014, $6.4 million and $4.5 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
	We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The note bears 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 maturity date of the note is July 20, 2023. As of December 31, 2013 and 2014, $4.6 million and $4.3 million, respectively, were outstanding on the note.

Property_and_Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2014
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,
			2013		2014
		Years	(In thousands)
	Oil and gas properties	—	$	564,755	$	716,922
	Equipment and other	Mar-39	17,237		18,608
	Drilling rig	15	21,722		22,075
			$	603,714	$	757,605

Stockbased_Compensation_Option

Stock-based Compensation, Option Plans and Warrants	12 Months Ended
	Dec. 31, 2014
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 (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 2012, 2013 and 2014:
		2012				2013				2014
	Weighted average value per option granted during the period	$	2.17			$	1.73			$	2.44
	Assumptions: (1)(2)
	Expected dividend yield	—		%		—		%		—		%
	Volatility	81.4		%		81.2		%		80.7		%
	Risk free interest rate	1.19		%		1.24		%		2.05		%
	Expected life (years)	6.7				6.5				6.6
	Fair value of options granted (in thousands)	$	1,324			$	1,444			$	2,666
	(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, 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
	Granted	1,091			$	3.38
	Exercised	(410	)		2.71
	Forfeited/Expired	(196	)		3.08
	Options outstanding December 31, 2014	5,885			$	2.88			5.9		$	2.06
	Exercisable at end of year	4,112							4.7		$	2.02
	Other information pertaining to the Company’s stock option activity for the three years ended December 31:
		2012				2013				2014
	Weighted average grant date fair value of stock options granted  (per share)	$	2.17			$	1.73			$	2.44
	Total fair value of options vested (000’s)	$	1,497			$	1,670			$	1,718
	Total intrinsic value of options exercised (000’s)	$	414			$	275			$	932
	As of December 31, 2014, the total compensation cost related to non-vested awards not yet recognized was approximately $2.6 million, which will be recognized in 2014 through 2017. For the years ended December 31, 2012, 2013 and 2014, we recognized $1.6 million, $1.7 million and $1.8 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, 2014:
		Options outstanding									Exercisable
					Weighted		Weighted						Weighted	Weighted
		Number			average		average				Number		average	average
		outstanding			remaining		exercise				exercisable		remaining	exercise
					life		price						life	price
	0.99 - 1.99	1,679,079			4.92		$	1.49			1,579,079		4.74	$	1.45
	2.00 - 2.99	1,414,200			6.8		$	2.34			940,077		6	$	2.31
	3.00 - 3.99	1,509,441			7.81		$	3.36			437,322		5.22	$	3.63
	4.00 - 4.99	1,109,750			3.55		$	4.58			987,375		3.14	$	4.57
	5.00 - 5.99	100,000			9.35		$	5.39			96,000		9.35	$	5.38
	6.00 - 6.28	73,000			1.26		$	6.05			72,000		1.15	$	6.05
		5,885,470									4,111,853
	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, 2014, the total compensation cost related to non-vested awards not yet recognized was approximately $4.7 million, which will be recognized in 2015 through 2018. For the years ended December 31, 2012, 2013 and 2014, we recognized $0.5 million, $0.4 million and $0.9 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, 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
Granted	1,582,000			3.49
Vested/Released	(121,622	)		3.64
Forfeited	(39,528	)		3.44
Unvested December 31, 2014	1,776,090			$	3.43
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. In March 2015 the director share awards were increased to 25,000 shares. 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 2011 and April 2012, directors were compensated for their annual retainer fee of $27,500 in cash. In April 2012 the retainer fee was increased to $40,000 and remained at $40,000 through 2014.
At December 31, 2014, the Company had approximately 7.3 million shares reserved for future issuance for conversion of its stock options, and incentive plans for the Company’s directors, employees and consultants.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
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,
		2012			2013			2014
		(In thousands)
	Deferred tax liabilities:
	Marketable securities	$	28		$	—		$	—
	Hedge contracts	—			—			8,114
	Other	—			3,152			4,458
	Total deferred tax liabilities	28			3,152			12,572
	Deferred tax assets:
	U.S. full cost pool	13,837			11,725			3,352
	Canada full cost pool	3,720			4,081			—
	Capital loss carryforward	—			—			12,325
	Depletion carryforward	4,930			4,743			4,936
	U.S. net operating loss  carryforward	59,362			49,667			50,941
	Canada net operating loss carryforward	4,196			5,736			—
	Alternative minimum tax credit	422			1,369			1,104
	Hedge contracts	2,231			1,397			—
	Other	1,042			—			—
	Total deferred tax assets	89,740			78,718			72,658
	Valuation allowance for deferred tax assets	(89,712		)	(75,566		)	(60,086		)
	Net deferred tax assets	28			3,152			12,572
	Net deferred tax	$	—		$	—		$	—
	Significant components of the provision (benefit) for income taxes are as follows:
		Years ended December 31,
		2012			2013			2014
		(In thousands)
	Current:
	Federal	$	310		$	632		$	(276	)
	State	—			68			(11		)
		$	310		$	700		$	(287	)
	Deferred:
	Federal	$	—		$	—		$	—
	Foreign	—			—			—
		$	—		$	—		$	—
	At December 31, 2014, the Company had, subject to the limitation discussed below, $145.5 million of net operating loss carryforwards for U.S. tax purposes.  The U.S. federal loss carryforward will expire in varying amounts through 2034, 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, 2014, 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 $89.7 million at December 31, 2012, $75.6 million at December 31, 2013 and $60.1 million at December 31, 2014.
	The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:
		Years ended December 31,
		2012			2013			2014
		(In thousands)
	Tax (expense) benefit at U.S. statutory rates (35%)	$	6,468		$	(13,771	)	$	(22,044	)
	(Increase) decrease in deferred tax asset valuation allowance	(6,231		)	14,146			15,480
	Rate differential for non US income	(1,533		)	(574		)	(39		)
	State income taxes	—			(47		)	—
	Accrual of prior year federal taxes (2009 and 2013)	(310		)	(81		)	287
	Permanent differences	(732		)	(743		)	(950		)
	Return to provision estimate revision	—			—			4,562
	Tax benefit related to the sale of Canadian subsidary	—			—			3,501
	Increase in asset  for partnership distribution	1,945			—			—
	Other	83			370			(510		)
		$	(310	)	$	(700	)	$	287
	During 2014, the Company decreased deferred tax assets by $6.0 million related to reductions in the full cost pool assets, the elimination of the Canadian full cost pooland net operating loss carryforward offset by the increase in the net capital 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, 2014 and 2013, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2004 through 2014 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, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Operating Leases
	The Company leases office space in Dickinson, North Dakota, Lusk, Wyoming and Denver, Colorado. During 2012, 2013 and 2014, rent expense incurred for the Dickinson, North Dakota office was $23,800, $26,073, and $26,265, respectively. The lease expires on October 31, 2016. Rent expense incurred for the Lusk, Wyoming office for 2012, 2013 and 2014 was $9,000 for each year. The lease expires on December 31, 2016. In 2013 the Company leased office space in Denver, Colorado, and rent expense incurred on this lease was $2,834 and $14,554 for 2013 and 2014, respectively. The lease expires on December 31, 2015.
	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, 2014, 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, 2014
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:
		2012			2013			2014
		(In thousands, except per share data)
	Numerator:
	Net income from continuing operations	$	3,106		$	46,841		$	61,951
	Net (loss) income from discontinued operations	(21,897		)	(8,194		)	1,318
		$	(18,791	)	$	38,647		$	63,269
	Denominator:
	Denominator for basic earnings per share – weighted-average common shares outstanding	91,914			92,451			98,835
	Effect of dilutive securities:	—			1,087			2,633
	Stock options and restricted shares
	Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares	91,914			93,538			101,468
	Net income (loss) per common share - basic
	Continuing operations	$	0.04		$	0.51		$	0.63
	Discontinued operations	(0.24		)	(0.09		)	0.01
		$	(0.20	)	$	0.42		$	0.64
	Net income (loss) per common share - diluted
	Continuing operations	$	0.04		$	0.5		$	0.61
	Discontinued operations	(0.24		)	(0.09		)	0.01
		$	(0.20	)	$	0.41		$	0.62
	Basic earnings per share, excluding any dilutive effects of stock options 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, 2013 and 2014.

Quarterly_Results_of_Operation

Quarterly Results of Operations (Unaudited)	12 Months Ended
	Dec. 31, 2014
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, 2013 and 2014 are as follows:
		1st		2nd		3rd		4th
		Quarter		Quarter		Quarter		Quarter
		(In thousands, except per share data)
	Year Ended December 31, 2013
	Net revenue	$	20,591	$	20,962	$	28,573	$	22,198
	Operating income	$	4,209	$	5,188	$	11,732	$	1,969
	Net income	$	595	$	7,866	$	3,190	$	26,996
	Net income per common share – basic	$	0.01	$	0.09	$	0.03	$	0.29
	Net income per common share – diluted	$	0.01	$	0.08	$	0.03	$	0.29
	Year Ended December 31, 2014
	Net revenue	$	25,518	$	33,192	$	43,874	$	31,192
	Operating income	$	7,695	$	12,603	$	16,783	$	2,842
	Net income	$	4,704	$	3,034	$	25,399	$	30,132
	Net income per common share – basic	$	0.05	$	0.03	$	0.24	$	0.29
	Net income per common share – diluted	$	0.05	$	0.03	$	0.24	$	0.28

Benefit_Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Benefit Plans	Benefit Plans
	The Company has a defined contribution plan (401(k) plan) covering all eligible employees. In 2012, 2013 and 2014, in accordance with the safe harbor provisions of the plan, the Company contributed $267,289, $284,865 and $313,899, 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 2012 was $17,000 for employees under the age of 50 and $22,500 for employees 50 years of age or older. The 2013 and  2014  contribution limit was $17,500 for employees under the age of 50 and $23,000 for employees 50 years of age or older.

Hedging_Program_and_Derivative

Hedging Program and Derivatives	12 Months Ended
	Dec. 31, 2014
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. There are no netting agreements relating to these derivative contracts and there is no policy to offset.
	The following table sets forth the summary position of our derivative contracts as of December 31, 2014:
		Oil - WTI					Gas
	Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)			Daily Volume (Mcf)		Swap Price (per Mcf)
	2015	1,045		$	85.04		1,450		$	4.08
	2016	948		$	84.1		—		$	—
	2017	493		$	84.18		—		$	—
	The following table illustrates the impact of derivative contracts on the Company’s balance sheet:
	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
	Fair Value of Derivative Instruments as of December 31, 2014
		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	$	12,214		Derivatives – current	$	13
	Commodity price derivatives	Derivatives – long-term	10,981			Derivatives – long-term	—
			$	23,195			$	13
	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, 2014
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, 2013 and 2014, 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)		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
			Quoted Prices		Significant
			in Active		Other
			Markets for		Observable		Significant		Balance as of
			Identical		Inputs		Unobservable		December 31,
			Assets		(Level 2)		Inputs (Level 3)		2014
			(Level 1)
	Assets:
	NYMEX Fixed Price Derivative contracts		$	—	$	23,195	$	—	$	23,195
	Total Assets		$	—	$	23,195	$	—	$	23,195
	Liabilities:
	NYMEX Fixed Price Derivative contracts		$	—	$	13	$	—	$	13
	Total Liabilities		$	—	$	13	$	—	$	13
	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.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations.
	On October 31, 2014, the Company closed on the sale of its Canadian subsidiary, Canadian Abraxas Petroleum, ULC ("Canadian Abraxas"). The sale was based on management's decision to discontinue Canadian operations due to continuing losses.
	In 2014, the Company recognized a gain on the sale of $1.9 million which is included in the accompanying Consolidated Statements of Operations as a component of net (loss) income from discontinued operations, net of tax.
	Canadian Abraxas revenue, reported in discontinued operations for the ten months ended October 31, 2014, and for the year ended December 31, 2013 was $1.2 million and $2.0 million, respectively. Canadian Abraxas net loss, reported in discontinued operations for the ten months ended October 31, 2014 and year ended December 31, 2013 was $0.6 million and $8.2 million, respectively.
	The following is a summary of the net assets of Canadian Abraxas as of December 31, 2013 and October 31, 2014.
		31-Dec-13		31-Oct-14
		(in thousands)
	Current assets	$	213	$	252
	Oil and gas properties - net	1,336		659
	Other assets	91		—
	Total Assets	1,640		911
	Accounts payable	224		275
	Accrued expenses	276		280
	Total liabilities	500		555
	Net assets of discontinued operation	$	1,140	$	356

Supplemental_Oil_and_Gas_Discl

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	15.  Supplemental Oil and Gas Disclosures (Unaudited)
	Information in the following tables is inclusive of Canadian operations that are presented in the basic financial statements as discontinued operations.
	The accompanying table presents information concerning the Company’s oil and gas producing activities inclusive of discontinued operations, 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
			2013				2014
			(In thousands)
	Proved oil and gas properties		$	564,755			$	716,922
	Unproved properties		—				—
	Total		564,755				716,922
	Accumulated depreciation, depletion, amortization and impairment		(413,704		)		(423,819		)
	Net capitalized costs		$	151,051			$	293,103
	Cost incurred in oil and gas property acquisition and development activities are as follows:
			Years Ended December 31
			2012				2013				2014
			(In thousands)
	Development costs		$	56,318			$	93,878			$	189,332
	Exploration costs		—				—				—
	Property acquisition costs		7,200				—				—
	Unproved		989				—				—
			$	64,507			$	93,878			$	189,332
	The results of operations for oil and gas producing activities, inclusive of discontinued operations, for the three years ended December 31, 2012, 2013 and 2014 are as follows:
			Years Ended December 31,
			2012				2013				2014
			(In thousands)
	Revenues		$	68,499			$	94,275			$	134,883
	Production costs		(31,419		)		(33,871		)		(38,146		)
	Depreciation, depletion, and amortization		(22,767		)		(26,072		)		(42,945		)
	Proved property impairment		(19,774		)		(6,025		)		—
	General and administrative		(2,679		)		(3,350		)		(2,796		)
	Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)		$	(8,140	)		$	24,957			$	50,996
	Depletion rate per barrel of oil equivalent		$	15.59			$	16.59			$	20.39
	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, 2012, 2013, and 2014.  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.
	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.
	For the period ending December 31, 2014, proved producing reserves were increased by approximately 4.4 MMBoe, net, due primarily to the completion of 20 new wells during 2014.  Ten of these new wells were located on the Company’s North Fork prospect acreage in McKenzie County, North Dakota, and ten were located on various acreage tracts in the Eagle Ford play of Atascosa and McMullen Counties, Texas.  The Company also added 28 new Bakken proved undeveloped down-spaced locations on the Company’s North Fork and Pershing prospect acreage in McKenzie County, North Dakota.  These locations were added based on the Company’s successful test of down-spacing from 1320 feet between wells in the same zone to 660 feet. Reserves attributable to these new down-spaced locations amounted to approximately 7.7 MMBoe, net.  The Company also gained approximately 1.1 MMBoe of net proved undeveloped reserves in the Bakken due to upward revisions in its Bakken type curve, which curve is used to forecast results on undeveloped locations.  These upward revisions were attributable to better-than-anticipated results in the Company’s existing Bakken producing wells.  The Company also gained proved undeveloped reserves of approximately 2.3 MMBbls of oil, net, due to the change in classification of ten probable undeveloped Bakken cases into the proved category. These locations achieved proved status by virtue of offsetting development activity during 2014. An equivalent volume of reserves was removed from the probable undeveloped category as a result of this change in classification.
			Oil/NGL			Gas			Oil
									Equivalents
			(MBbl)			(MMcf)			(MBoe)
			(In thousands)
	Proved developed and undeveloped reserves:
	Balance at December 31, 2011		14,219			72,075			26,232
	Revisions of previous estimates		1,574			(7,470	)		328
	Extensions and discoveries		5,809			6,983			6,973
	Purchase of minerals in place		1			69			13
	Sales of minerals in place		(850	)		(6,376	)		(1,913	)
	Production		(797	)		(4,097	)		(1,481	)
	Balance at December 31, 2012		19,956			61,184			30,152
	Revisions of previous estimates		999			(5,123	)		145
	Extensions and discoveries		10,746			3,610			11,348
	Sales of minerals in place		(7,748	)		(8,141	)		(9,105	)
	Production		(1,000	)		(3,421	)		(1,570	)
	Balance at December 31, 2013		22,953			48,109			30,970
	Revisions of previous estimates		3,718			7,383			4,950
	Extensions and discoveries		8,648			6,893			9,797
	Sales of minerals in place		(620	)		(3,614	)		(1,223	)
	Production		(1,601	)		(2,918	)		(2,088	)
	Balance at December 31, 2014		33,098			55,853			42,406
			Total
			Oil/NGL			Gas			Oil
									Equivalents
			(MBbl)			(MMcf)			(MBoe)
			(In thousands)
	Proved Developed Reserves:
	December 31, 2012		8,650			41,220			15,520
December 31, 2013		8,310			31,572			13,572
December 31, 2014		12,168			34,677			17,948
Proved Undeveloped Reserves:
December 31, 2012		11,306			19,964			14,634
December 31, 2013		14,640			16,537			17,397
December 31, 2014		20,930			21,176			24,459
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, 2012, 2013 and 2014. 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 2014, 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 11, 2015, 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, 2012, 2013 and 2014 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 36 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.
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, 2012, 2013 and 2014:
		Years Ended December 31,
		2012				2013				2014
		(In thousands)
Future cash inflows		$	1,784,920			$	2,244,846			$	2,988,464
Future production costs		(642,706		)		(754,722		)		(921,977		)
Future development costs		(328,554		)		(467,206		)		(557,782		)
Future income tax expense		(149,625		)		(244,394		)		(373,095		)
Future net cash flows		664,035				778,524				1,135,610
Discount		(385,890		)		(437,539		)		(623,053		)
Standardized Measure of discounted future net cash relating to proved reserves		$	278,145			$	340,985			$	512,557
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,
		2012				2013				2014
		(In thousands)
Standardized Measure, beginning of year		$	269,082			$	278,145			$	340,985
Sales and transfers of oil and gas produced, net of production costs		(37,080		)		(60,403		)		(96,364		)
Net change in prices and development and production costs from prior year		60,710				169,969				150,504
Extensions, discoveries, and improved recovery, less related costs		73,236				156,456				147,275
Sales of minerals in place		(20,089		)		(125,533		)		(15,042		)
Purchased of minerals in place		131				—				—
Revisions of previous quantity estimates		3,355				2,930				74,390
Change in timing and other		(88,309		)		(62,861		)		(82,653		)
Change in future income tax expense		(9,799		)		(45,532		)		(40,636		)
Accretion of discount		26,908				27,814				34,098
Standardized Measure, end of year		$	278,145			$	340,985			$	512,557
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,
		2012				2013				2014
Oil (per Bbl) (1)		$	95.14			$	97.33			$	95.28
Gas (per MMbtu) (2)		$	2.86			$	3.67			$	4.35
Oil (per Bbl) (3)		$	88.26			$	95.9			$	87.11
Gas (per MMBtu) (4)		$	2.61			$	3.65			$	5.15
NGL’s (per Bbl) (5)		$	36.76			$	31.98			$	37.91
_____________________
-1	The quoted oil price for the year ended December 31 of each year, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2012, 2013 and 2014.
-2	The quoted gas price for the year ended December 31, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2012, 2013 and 2014.
-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, 2014
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.  Our oil and gas assets are located in three operating regions in the United States, the Rocky Mountain, Permian Basin and onshore Gulf Coast.
	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”).
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 $407,000 at December 31, 2013 and 2014. 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, 2012, 2013 and 2014, our net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves.
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, 2013 and 2014, and costs as of December 31, 2013 and 2014. 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 (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, 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, 2013 and 2014.
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 $60.1 million for deferred tax assets at December 31, 2014.
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. During the year ended December 31, 2014, other comprehensive income of $0.6 million representing translation adjustments for the Company’s former Canadian operations were reflected in net income from discontinued operations. There is no accumulated other comprehensive income as of December 31, 2014.
	New Accounting Standards and Disclosures
	Revenue Recognition
	The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014 which provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. The requirements from the new ASU are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The standard allows for either full retrospective adoption or modified retrospective adoption. At this time, we are evaluating the guidance to determine the method of adoption and the impact of this ASU on our financial statements and related disclosures, if any.

Organization_and_Significant_A2

Organization and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
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:
			2013			2014
		(in thousands)
	Beginning asset retirement obligation		$	11,381		$	9,888
	New wells placed on production and other		183			444
	Deletions related to property disposals and plugging costs		(2,491		)	(1,318		)
	Accretion expense		615			559
	Revisions		151			198
	Discontinued operations		49			(276		)
	Ending asset retirement obligation		$	9,888		$	9,495

Joint_Venture_Tables

Joint Venture (Tables)	12 Months Ended
	Dec. 31, 2014
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) financial statements:
			Year Ended
			December 31,
	Statement of Operations:		2012 (1)
		(in thousands)
	Revenue		$	12,106
	Operating expenses		7,144
	Other income		(4		)
	Net income		$	4,966
	(1) Through August 31, 2012

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-term Debt	The following is a description of the Company’s debt as of December 31, 2013 and 2014, respectively:
			December 31,			December 31,
			2013			2014
			(In thousands)
	Senior secured credit facility		$	33,000		$	70,000
	Rig loan agreement		6,378			4,456
	Real estate lien note		4,554			4,333
			43,932			78,789
	Less current maturities		(2,142		)	(2,235		)
			$	41,790		$	76,554
Maturities of Long-term Debt	Maturities of long-term debt are as follows:
	Year ending December 31, (In thousands)
	2015	$	2,235
	2016	2,333
	2017	608
	2018	70,262
	2019	273
	Thereafter	3,078
		$	78,789

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
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,
			2013		2014
		Years	(In thousands)
	Oil and gas properties	—	$	564,755	$	716,922
	Equipment and other	Mar-39	17,237		18,608
	Drilling rig	15	21,722		22,075
			$	603,714	$	757,605

Stockbased_Compensation_Option1

Stock-based Compensation, Option Plans and Warrants (Tables)	12 Months Ended
	Dec. 31, 2014
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 (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 2012, 2013 and 2014:
		2012				2013				2014
	Weighted average value per option granted during the period	$	2.17			$	1.73			$	2.44
	Assumptions: (1)(2)
	Expected dividend yield	—		%		—		%		—		%
	Volatility	81.4		%		81.2		%		80.7		%
	Risk free interest rate	1.19		%		1.24		%		2.05		%
	Expected life (years)	6.7				6.5				6.6
	Fair value of options granted (in thousands)	$	1,324			$	1,444			$	2,666
	(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, 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
	Granted	1,091			$	3.38
	Exercised	(410	)		2.71
	Forfeited/Expired	(196	)		3.08
	Options outstanding December 31, 2014	5,885			$	2.88			5.9		$	2.06
	Exercisable at end of year	4,112							4.7		$	2.02
	Other information pertaining to the Company’s stock option activity for the three years ended December 31:
		2012				2013				2014
	Weighted average grant date fair value of stock options granted  (per share)	$	2.17			$	1.73			$	2.44
	Total fair value of options vested (000’s)	$	1,497			$	1,670			$	1,718
	Total intrinsic value of options exercised (000’s)	$	414			$	275			$	932
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, 2014:
		Options outstanding									Exercisable
					Weighted		Weighted						Weighted	Weighted
		Number			average		average				Number		average	average
		outstanding			remaining		exercise				exercisable		remaining	exercise
					life		price						life	price
	0.99 - 1.99	1,679,079			4.92		$	1.49			1,579,079		4.74	$	1.45
	2.00 - 2.99	1,414,200			6.8		$	2.34			940,077		6	$	2.31
	3.00 - 3.99	1,509,441			7.81		$	3.36			437,322		5.22	$	3.63
	4.00 - 4.99	1,109,750			3.55		$	4.58			987,375		3.14	$	4.57
	5.00 - 5.99	100,000			9.35		$	5.39			96,000		9.35	$	5.38
	6.00 - 6.28	73,000			1.26		$	6.05			72,000		1.15	$	6.05
		5,885,470									4,111,853
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, 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
	Granted	1,582,000			3.49
	Vested/Released	(121,622	)		3.64
	Forfeited	(39,528	)		3.44
	Unvested December 31, 2014	1,776,090			$	3.43

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2012			2013			2014
		(In thousands)
	Deferred tax liabilities:
	Marketable securities	$	28		$	—		$	—
	Hedge contracts	—			—			8,114
	Other	—			3,152			4,458
	Total deferred tax liabilities	28			3,152			12,572
	Deferred tax assets:
	U.S. full cost pool	13,837			11,725			3,352
	Canada full cost pool	3,720			4,081			—
	Capital loss carryforward	—			—			12,325
	Depletion carryforward	4,930			4,743			4,936
	U.S. net operating loss  carryforward	59,362			49,667			50,941
	Canada net operating loss carryforward	4,196			5,736			—
	Alternative minimum tax credit	422			1,369			1,104
	Hedge contracts	2,231			1,397			—
	Other	1,042			—			—
	Total deferred tax assets	89,740			78,718			72,658
	Valuation allowance for deferred tax assets	(89,712		)	(75,566		)	(60,086		)
	Net deferred tax assets	28			3,152			12,572
	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,
		2012			2013			2014
		(In thousands)
	Current:
	Federal	$	310		$	632		$	(276	)
	State	—			68			(11		)
		$	310		$	700		$	(287	)
	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,
		2012			2013			2014
		(In thousands)
	Tax (expense) benefit at U.S. statutory rates (35%)	$	6,468		$	(13,771	)	$	(22,044	)
	(Increase) decrease in deferred tax asset valuation allowance	(6,231		)	14,146			15,480
	Rate differential for non US income	(1,533		)	(574		)	(39		)
	State income taxes	—			(47		)	—
	Accrual of prior year federal taxes (2009 and 2013)	(310		)	(81		)	287
	Permanent differences	(732		)	(743		)	(950		)
	Return to provision estimate revision	—			—			4,562
	Tax benefit related to the sale of Canadian subsidary	—			—			3,501
	Increase in asset  for partnership distribution	1,945			—			—
	Other	83			370			(510		)
		$	(310	)	$	(700	)	$	287

Earnings_per_Share_Tables

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		2012			2013			2014
		(In thousands, except per share data)
	Numerator:
	Net income from continuing operations	$	3,106		$	46,841		$	61,951
	Net (loss) income from discontinued operations	(21,897		)	(8,194		)	1,318
		$	(18,791	)	$	38,647		$	63,269
	Denominator:
	Denominator for basic earnings per share – weighted-average common shares outstanding	91,914			92,451			98,835
	Effect of dilutive securities:	—			1,087			2,633
	Stock options and restricted shares
	Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares	91,914			93,538			101,468
	Net income (loss) per common share - basic
	Continuing operations	$	0.04		$	0.51		$	0.63
	Discontinued operations	(0.24		)	(0.09		)	0.01
		$	(0.20	)	$	0.42		$	0.64
	Net income (loss) per common share - diluted
	Continuing operations	$	0.04		$	0.5		$	0.61
	Discontinued operations	(0.24		)	(0.09		)	0.01
		$	(0.20	)	$	0.41		$	0.62

Quarterly_Results_of_Operation1

Quarterly Results of Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2013 and 2014 are as follows:
		1st		2nd		3rd		4th
		Quarter		Quarter		Quarter		Quarter
		(In thousands, except per share data)
	Year Ended December 31, 2013
	Net revenue	$	20,591	$	20,962	$	28,573	$	22,198
	Operating income	$	4,209	$	5,188	$	11,732	$	1,969
	Net income	$	595	$	7,866	$	3,190	$	26,996
	Net income per common share – basic	$	0.01	$	0.09	$	0.03	$	0.29
	Net income per common share – diluted	$	0.01	$	0.08	$	0.03	$	0.29
	Year Ended December 31, 2014
	Net revenue	$	25,518	$	33,192	$	43,874	$	31,192
	Operating income	$	7,695	$	12,603	$	16,783	$	2,842
	Net income	$	4,704	$	3,034	$	25,399	$	30,132
	Net income per common share – basic	$	0.05	$	0.03	$	0.24	$	0.29
	Net income per common share – diluted	$	0.05	$	0.03	$	0.24	$	0.28

Hedging_Program_and_Derivative1

Hedging Program and Derivatives (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014:
		Oil - WTI					Gas
	Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)			Daily Volume (Mcf)		Swap Price (per Mcf)
	2015	1,045		$	85.04		1,450		$	4.08
	2016	948		$	84.1		—		$	—
	2017	493		$	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, 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
	Fair Value of Derivative Instruments as of December 31, 2014
		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	$	12,214		Derivatives – current	$	13
	Commodity price derivatives	Derivatives – long-term	10,981			Derivatives – long-term	—
			$	23,195			$	13

Financial_Instruments_Tables

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2013 and 2014, 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)		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
		Quoted Prices		Significant
		in Active		Other
		Markets for		Observable		Significant		Balance as of
		Identical		Inputs		Unobservable		December 31,
		Assets		(Level 2)		Inputs (Level 3)		2014
		(Level 1)
	Assets:
	NYMEX Fixed Price Derivative contracts	$	—	$	23,195	$	—	$	23,195
	Total Assets	$	—	$	23,195	$	—	$	23,195
	Liabilities:
	NYMEX Fixed Price Derivative contracts	$	—	$	13	$	—	$	13
	Total Liabilities	$	—	$	13	$	—	$	13

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations	The following is a summary of the net assets of Canadian Abraxas as of December 31, 2013 and October 31, 2014.
		31-Dec-13		31-Oct-14
		(in thousands)
	Current assets	$	213	$	252
	Oil and gas properties - net	1,336		659
	Other assets	91		—
	Total Assets	1,640		911
	Accounts payable	224		275
	Accrued expenses	276		280
	Total liabilities	500		555
	Net assets of discontinued operation	$	1,140	$	356

Supplemental_Oil_and_Gas_Discl1

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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 inclusive of discontinued operations, 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
			2013				2014
			(In thousands)
	Proved oil and gas properties		$	564,755			$	716,922
	Unproved properties		—				—
	Total		564,755				716,922
	Accumulated depreciation, depletion, amortization and impairment		(413,704		)		(423,819		)
	Net capitalized costs		$	151,051			$	293,103
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
			2012				2013				2014
			(In thousands)
	Development costs		$	56,318			$	93,878			$	189,332
	Exploration costs		—				—				—
	Property acquisition costs		7,200				—				—
	Unproved		989				—				—
			$	64,507			$	93,878			$	189,332
Results of Operations for Oil and Gas Producing Activities	The results of operations for oil and gas producing activities, inclusive of discontinued operations, for the three years ended December 31, 2012, 2013 and 2014 are as follows:
			Years Ended December 31,
			2012				2013				2014
			(In thousands)
	Revenues		$	68,499			$	94,275			$	134,883
	Production costs		(31,419		)		(33,871		)		(38,146		)
	Depreciation, depletion, and amortization		(22,767		)		(26,072		)		(42,945		)
	Proved property impairment		(19,774		)		(6,025		)		—
	General and administrative		(2,679		)		(3,350		)		(2,796		)
	Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)		$	(8,140	)		$	24,957			$	50,996
	Depletion rate per barrel of oil equivalent		$	15.59			$	16.59			$	20.39
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.
	For the period ending December 31, 2014, proved producing reserves were increased by approximately 4.4 MMBoe, net, due primarily to the completion of 20 new wells during 2014.  Ten of these new wells were located on the Company’s North Fork prospect acreage in McKenzie County, North Dakota, and ten were located on various acreage tracts in the Eagle Ford play of Atascosa and McMullen Counties, Texas.  The Company also added 28 new Bakken proved undeveloped down-spaced locations on the Company’s North Fork and Pershing prospect acreage in McKenzie County, North Dakota.  These locations were added based on the Company’s successful test of down-spacing from 1320 feet between wells in the same zone to 660 feet. Reserves attributable to these new down-spaced locations amounted to approximately 7.7 MMBoe, net.  The Company also gained approximately 1.1 MMBoe of net proved undeveloped reserves in the Bakken due to upward revisions in its Bakken type curve, which curve is used to forecast results on undeveloped locations.  These upward revisions were attributable to better-than-anticipated results in the Company’s existing Bakken producing wells.  The Company also gained proved undeveloped reserves of approximately 2.3 MMBbls of oil, net, due to the change in classification of ten probable undeveloped Bakken cases into the proved category. These locations achieved proved status by virtue of offsetting development activity during 2014. An equivalent volume of reserves was removed from the probable undeveloped category as a result of this change in classification.
			Oil/NGL			Gas			Oil
									Equivalents
			(MBbl)			(MMcf)			(MBoe)
			(In thousands)
	Proved developed and undeveloped reserves:
	Balance at December 31, 2011		14,219			72,075			26,232
	Revisions of previous estimates		1,574			(7,470	)		328
	Extensions and discoveries		5,809			6,983			6,973
	Purchase of minerals in place		1			69			13
	Sales of minerals in place		(850	)		(6,376	)		(1,913	)
	Production		(797	)		(4,097	)		(1,481	)
	Balance at December 31, 2012		19,956			61,184			30,152
	Revisions of previous estimates		999			(5,123	)		145
	Extensions and discoveries		10,746			3,610			11,348
	Sales of minerals in place		(7,748	)		(8,141	)		(9,105	)
	Production		(1,000	)		(3,421	)		(1,570	)
	Balance at December 31, 2013		22,953			48,109			30,970
	Revisions of previous estimates		3,718			7,383			4,950
	Extensions and discoveries		8,648			6,893			9,797
	Sales of minerals in place		(620	)		(3,614	)		(1,223	)
	Production		(1,601	)		(2,918	)		(2,088	)
	Balance at December 31, 2014		33,098			55,853			42,406
			Total
			Oil/NGL			Gas			Oil
									Equivalents
			(MBbl)			(MMcf)			(MBoe)
			(In thousands)
	Proved Developed Reserves:
	December 31, 2012		8,650			41,220			15,520
	December 31, 2013		8,310			31,572			13,572
	December 31, 2014		12,168			34,677			17,948
	Proved Undeveloped Reserves:
	December 31, 2012		11,306			19,964			14,634
	December 31, 2013		14,640			16,537			17,397
	December 31, 2014		20,930			21,176			24,459
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, 2012, 2013 and 2014:
			Years Ended December 31,
			2012				2013				2014
			(In thousands)
	Future cash inflows		$	1,784,920			$	2,244,846			$	2,988,464
	Future production costs		(642,706		)		(754,722		)		(921,977		)
	Future development costs		(328,554		)		(467,206		)		(557,782		)
	Future income tax expense		(149,625		)		(244,394		)		(373,095		)
	Future net cash flows		664,035				778,524				1,135,610
	Discount		(385,890		)		(437,539		)		(623,053		)
	Standardized Measure of discounted future net cash relating to proved reserves		$	278,145			$	340,985			$	512,557
Analysis of Changes in Standardized Measure	The following is an analysis of the changes in the Standardized Measure:
			Year Ended December 31,
			2012				2013				2014
			(In thousands)
	Standardized Measure, beginning of year		$	269,082			$	278,145			$	340,985
	Sales and transfers of oil and gas produced, net of production costs		(37,080		)		(60,403		)		(96,364		)
	Net change in prices and development and production costs from prior year		60,710				169,969				150,504
	Extensions, discoveries, and improved recovery, less related costs		73,236				156,456				147,275
	Sales of minerals in place		(20,089		)		(125,533		)		(15,042		)
	Purchased of minerals in place		131				—				—
	Revisions of previous quantity estimates		3,355				2,930				74,390
	Change in timing and other		(88,309		)		(62,861		)		(82,653		)
	Change in future income tax expense		(9,799		)		(45,532		)		(40,636		)
	Accretion of discount		26,908				27,814				34,098
	Standardized Measure, end of year		$	278,145			$	340,985			$	512,557
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,
			2012				2013				2014
	Oil (per Bbl) (1)		$	95.14			$	97.33			$	95.28
	Gas (per MMbtu) (2)		$	2.86			$	3.67			$	4.35
	Oil (per Bbl) (3)		$	88.26			$	95.9			$	87.11
	Gas (per MMBtu) (4)		$	2.61			$	3.65			$	5.15
	NGL’s (per Bbl) (5)		$	36.76			$	31.98			$	37.91
	_____________________
	-1	The quoted oil price for the year ended December 31 of each year, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2012, 2013 and 2014.
	-2	The quoted gas price for the year ended December 31, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2012, 2013 and 2014.
	-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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	region
Nature of operations [Abstract]
Number of operating regions in domicile country	3
Accounts Receivable [Abstract]
Allowance for doubtful accounts	$407	$407
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%
Share-Based Payments [Abstract]
Stock-based compensation expense	2,703	2,114	2,091
Entity's asset retirement obligation transactions [Roll Forward]
Beginning asset retirement obligation	9,888	11,381
New wells placed on production and other	444	183
Deletions related to property disposals and plugging costs	-1,318	-2,491
Accretion expense	-559	-615	-457
Revisions	198	151
Discontinued operations	-276	49
Ending asset retirement obligation	9,495	9,888	11,381
Revenue Recognition and Major Purchasers [Abstract]
Entity wide revenue, major customers (in hundredths)	62.00%	49.00%	39.00%
Entity wide revenue, number of major purchasers of oil and gas	2	2	3
Income Taxes [Abstract]
Valuation allowance for deferred tax assets	$60,086	$75,566	$89,712

Joint_Venture_Details

Joint Venture (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Gain from equity method investments	$0	$0	$2,207
Blue Eagle [Member]
Statement of Operations [Abstract]
Revenue			12,106
Operating expenses			7,144
Other income			-4
Net income			$4,966

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	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	acre						acre
Divestiture of Non Core Properties [Abstract]
Net proceeds from divestiture of non-core properties	$71,400,000		$2,500,000	$2,600,000	$21,500,000	$900,000	$6,600,000
Proceeds from Monetization of Assets		38,300,000					10,600,000
Area of Real Estate Property	2,563						2,563
Proceeds from other property sales during the year							600,000
Gain (Loss) on Sale of Property	$33,400,000					$0	$33,377,000	$0

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Feb. 14, 2012	Jul. 20, 2013	Dec. 31, 2013	Sep. 19, 2011
	borrowing_base				hp
Long-term debt [Abstract]
Long-term debt	$78,789,000			$43,932,000
Less current maturities	-2,235,000			-2,142,000
Long-term debt – less current maturities	76,554,000			41,790,000
Maturities of long-term debt [Abstract]
2015	2,235,000
2016	2,333,000
2017	608,000
2018	70,262,000
2019	273,000
Thereafter	3,078,000
Credit Facility [Abstract]
Maximum borrowing capacity	300,000,000
Current borrowing base	165,000,000
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
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	42.81
Total debt to EBITDAX ratio	0.82
Current ratio	1.53
Senior Secured Credit Facility [Member]
Long-term debt [Abstract]
Long-term debt	70,000,000			33,000,000
Maturities of long-term debt [Abstract]
Maturity date of debt instrument	30-Jun-18
Percentage added to reference rate (in hundredths)	0.50%
Credit Facility [Abstract]
Market value of property (in hundredths)	5.00%
Reduced collateral value (in hundredths)	5.00%
Interest rate on credit facility (in hundredths)	2.16%
Senior Secured Credit Facility [Member] | Minimum [Member]
Maturities of long-term debt [Abstract]
Percentage added to reference rate (in hundredths)	0.75%
Credit Facility [Abstract]
Percentage added to variable rate of interest (in hundredths)	1.75%
Senior Secured Credit Facility [Member] | Maximum [Member]
Maturities of long-term debt [Abstract]
Percentage added to reference rate (in hundredths)	1.75%
Credit Facility [Abstract]
Percentage added to variable rate of interest (in hundredths)	2.75%
Rig Loan Agreement [Member]
Long-term debt [Abstract]
Long-term debt	4,456,000			6,378,000
Maturities of long-term debt [Abstract]
Maturity date of debt instrument		14-Feb-17
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
Interest rate on debt (in hundredths)		4.26%
Real Estate Lien Note [Abstract]
Monthly installments of principal and interest	179,695
Real Estate Lien Note [Member]
Long-term debt [Abstract]
Long-term debt	4,333,000			4,554,000
Real Estate Lien Note [Abstract]
Fixed interest rate on note (in hundredths)			4.25%
Monthly installments of principal and interest			$34,354
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, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property and equipment	$757,605	$603,714
Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property and equipment	716,922	564,755
Equipment and Other [Member]
Property, Plant and Equipment [Line Items]
Property and equipment	18,608	17,237
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	$22,075	$21,722

Stockbased_Compensation_Option2

Stock-based Compensation, Option Plans and Warrants (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 12, 2015	Apr. 30, 2012	Mar. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$2,703,000	$2,114,000	$2,091,000
Director Stock Awards [Abstract]
Shares reserved for issuance (in shares)	7,317,368
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding, Number (in shares)	5,885,470
Exercisable, Number (in shares)	4,111,853
$0.99 - 1.99
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)	$1
Stock option plans exercise price range, upper limit (in dollars per share)	$1.99
Options outstanding, Number (in shares)	1,679,079
Options outstanding, Weighted average remaining life	4 years 11 months 1 day
Options outstanding, Weighted average exercise price (in dollars per share)	$1.49
Exercisable, Number (in shares)	1,579,079
Exercisable, Weighted average remaining life	4 years 8 months 27 days
Exercisable, Weighted average exercise price (in dollars per share)	$1.45
$2.00 - 2.99
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)	$2
Stock option plans exercise price range, upper limit (in dollars per share)	$2.99
Options outstanding, Number (in shares)	1,414,200
Options outstanding, Weighted average remaining life	6 years 9 months 18 days
Options outstanding, Weighted average exercise price (in dollars per share)	$2.34
Exercisable, Number (in shares)	940,077
Exercisable, Weighted average remaining life	6 years
Exercisable, Weighted average exercise price (in dollars per share)	$2.31
$3.00 - 3.99
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)	$3
Stock option plans exercise price range, upper limit (in dollars per share)	$3.99
Options outstanding, Number (in shares)	1,509,441
Options outstanding, Weighted average remaining life	7 years 9 months 22 days
Options outstanding, Weighted average exercise price (in dollars per share)	$3.36
Exercisable, Number (in shares)	437,322
Exercisable, Weighted average remaining life	5 years 2 months 19 days
Exercisable, Weighted average exercise price (in dollars per share)	$3.63
$4.00 - 4.99
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)	$4
Stock option plans exercise price range, upper limit (in dollars per share)	$4.99
Options outstanding, Number (in shares)	1,109,750
Options outstanding, Weighted average remaining life	3 years 6 months 18 days
Options outstanding, Weighted average exercise price (in dollars per share)	$4.58
Exercisable, Number (in shares)	987,375
Exercisable, Weighted average remaining life	3 years 1 month 21 days
Exercisable, Weighted average exercise price (in dollars per share)	$4.57
$5.00 - 5.99
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)	$5
Stock option plans exercise price range, upper limit (in dollars per share)	$5.99
Options outstanding, Number (in shares)	100,000
Options outstanding, Weighted average remaining life	9 years 4 months 6 days
Options outstanding, Weighted average exercise price (in dollars per share)	$5.39
Exercisable, Number (in shares)	96,000
Exercisable, Weighted average remaining life	9 years 4 months 6 days
Exercisable, Weighted average exercise price (in dollars per share)	$5.38
$6.00 - 6.28
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)	$6
Stock option plans exercise price range, upper limit (in dollars per share)	$6.28
Options outstanding, Number (in shares)	73,000
Options outstanding, Weighted average remaining life	1 year 3 months 4 days
Options outstanding, Weighted average exercise price (in dollars per share)	$6.05
Exercisable, Number (in shares)	72,000
Exercisable, Weighted average remaining life	1 year 1 month 24 days
Exercisable, Weighted average exercise price (in dollars per share)	$6.05
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	1,820,000	1,700,000	1,600,000
Weighted average assumptions used in fair value of the options [Abstract]
Weighted average value per option granted during the period (in dollars per share)	$2.44	$1.73	$2.17
Assumptions [Abstract]
Expected dividend yield (in hundredths)	0.00%	0.00%	0.00%
Volatility (in hundredths)	80.70%	81.20%	81.40%
Risk free interest rate (in hundredths)	2.05%	1.24%	1.19%
Expected life (years)	6 years 7 months 6 days	6 years 6 months	6 years 8 months 12 days
Fair value of options granted	2,666,000	1,444,000	1,324,000
Authorized shares available for grant (in shares)	5,200,000
Options expiration period	10 years
Options [Roll Forward]
Options outstanding, beginning balance (in shares)	5,400,000	4,761,000	4,756,000
Granted (in shares)	1,091,000	836,000	610,000
Exercised (in shares)	-410,000	-166,000	-391,000
Forfeited/Expired (in shares)	-196,000	-31,000	-214,000
Options outstanding, ending balance (in shares)	5,885,000	5,400,000	4,761,000
Exercisable at end of year (in shares)	4,112,000
Weighted average exercise price [Roll Forward]
Options outstanding, beginning balance (in dollars per share)	$2.77	$2.77	$2.61
Granted (in dollars per share)	$3.38	$2.43	$3.01
Exercised (in dollars per share)	$2.71	$1.18	$1.11
Forfeited/Expired (in dollars per share)	$3.08	$2.58	$2.80
Options outstanding, ending balance (in dollars per share)	$2.88	$2.77	$2.77
Options outstanding weighted average exercise price of options exercisable
Weighted average remaining life [Abstract]
Options outstanding ending balance	5 years 10 months 24 days
Exercisable at end of year	4 years 8 months 12 days
Fair value per share [Abstract]
Options outstanding, ending balance (in dollars per share)	$2.06
Exercisable at end of year, Fair value (in dollars per share)	$2.02
Other information pertaining to stock options activity [Abstract]
Weighted average grant date fair value of stock options granted (in dollars per share)	$2.44	$1.73	$2.17
Total fair value of options vested	1,718,000	1,670,000	1,497,000
Total intrinsic value of options exercised	932,000	275,000	414,000
Compensation cost related to non-vested awards not yet recognized	2,590,000
Restricted Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	883,000	400,000	500,000
Restricted Stock Awards [Abstract]
Compensation cost not yet recognized	4,651,000
Number of Shares [Roll Forward]
Unvested, Beginning balance (in shares)	355,240	482,025	629,771
Granted (in shares)	1,582,000	48,222	89,860
Vested/Released (in shares)	-121,622	-169,700	-229,172
Forfeited (in shares)	-39,528	-5,307	-8,434
Unvested, Ending balance (in shares)	1,776,090	355,240	482,025
Weighted average grant date fair value [Roll Forward]
Unvested, beginning balance (in dollars per share)	$3.24	$3.09	$3.03
Granted (in dollars per share)	$3.49	$2.69	$2.12
Vested/Released (in dollars per share)	$3.64	$2.66	$2.57
Forfeited (in dollars per share)	$3.44	$3.08	$2.42
Unvested, Ending balance (in dollars per share)	$3.43	$3.24	$3.09
2005 Directors Plan [Member]
Director Stock Awards [Abstract]
Shares reserved for issuance (in shares)	1,500,000
Number of shares to be granted for participation in board and committee meetings as per agreement (in shares)	12,000			25,000
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

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 23, 2013
Deferred tax liabilities [Abstract]
Marketable securities	$0	$0	$28
Hedge contracts	8,114	0	0
Deferred Tax Liabilities, Other	4,458	3,152	0
Total deferred tax liabilities	12,572	3,152	28
Deferred tax assets [Abstract]
U.S. full cost pool	3,352	11,725	13,837
Deferred tax assets additional full cost pool	0	4,081	3,720
Deferred Tax Assets, Capital Loss Carryforwards	12,325	0	0
Depletion carryforward	4,936	4,743	4,930
U.S. net operating loss carryforward	50,941	49,667	59,362
Deferred Tax Assets, Operating Loss Carryforwards, Foreign	0	5,736	4,196
Alternative minimum tax credit	1,104	1,369	422
Hedge contracts	0	1,397	2,231
Other	0	0	1,042
Total deferred tax assets	72,658	78,718	89,740
Valuation allowance for deferred tax assets	-60,086	-75,566	-89,712
Net deferred tax assets	12,572	3,152	28
Net deferred tax	0	0	0
Current [Abstract]
Federal	-276	632	310
State	-11	68	0
Current provision (benefit) for income taxes	-287	700	310
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
Tax Adjustments, Settlements, and Unusual Provisions		81
Reconciliation of income tax computed at U.S federal statutory tax rates [Abstract]
Tax (expense) benefit at U.S. statutory rates (35%)	-22,044	-13,771	6,468
(Increase) decrease in deferred tax asset valuation allowance	15,480	14,146	-6,231
Rate differential for non US income	-39	-574	-1,533
State income taxes	0	-47	0
Accrual of prior year federal taxes (2009)	287	-81	-310
Permanent differences	-950	-743	-732
Return to provision estimate revision	4,562	0	0
Tax benefit related to the sale of Canadian subsidary	3,501	0	0
Increase in asset for partnership distributions	0	0	1,945
Other	-510	370	83
Income tax (expense) benefit	287	-700	-310
U.S statutory rate (in hundredths)	35.00%
Reduction in deferred tax assets	-6,000
Tax adjustment assessed		619	310
U.S. Tax [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$145,500
Expiration dates of operating loss carryforwards	31-Dec-34

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Office Space in Dickinson, North Dakota [Member]
Operating Leased Assets [Line Items]
Rent expense	$26,265	$26,073	$23,800
Office Space in Lusk, Wyoming [Member]
Operating Leased Assets [Line Items]
Rent expense	9,000	9,000	9,000
Office Space in Denver, Colorado [Member]
Operating Leased Assets [Line Items]
Rent expense	$14,554	$2,834

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator [Abstract]
Net income from continuing operations									$61,951	$46,841	$3,106
Net (loss) income from discontinued operations									1,318	-8,194	-21,897
Net income (loss)	$30,132	$25,399	$3,034	$4,704	$26,996	$3,190	$7,866	$595	$63,269	$38,647	($18,791)
Denominator [Abstract]
Denominator for basic earnings per share – weighted-average common shares outstanding (shares)									98,835,000	92,451,000	91,914,000
Effect of dilutive securities [Abstract]
Stock options, restricted shares and warrants (in shares)									2,633,000	1,087,000	0
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)									101,468,000	93,538,000	91,914,000
Earnings Per Share, Basic [Abstract]
Continuing operations (in dollars per share)									$0.63	$0.51	$0.04
Discontinued operations (in dollars per share)									$0.01	($0.09)	($0.24)
Total (in dollars per share)	$0.29	$0.24	$0.03	$0.05	$0.29	$0.03	$0.09	$0.01	$0.64	$0.42	($0.20)
Earnings Per Share, Diluted [Abstract]
Continuing operations (in dollars per share)									$0.61	$0.50	$0.04
Discontinued operations (in dollars per share)									$0.01	($0.09)	($0.24)
Total (in dollars per share)	$0.28	$0.24	$0.03	$0.05	$0.29	$0.03	$0.08	$0.01	$0.62	$0.41	($0.20)
Stock options excluded from the calculation of diluted income (loss) per share (in shares)									0	0	1,349

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Net revenue	$31,192	$43,874	$33,192	$25,518	$22,198	$28,573	$20,962	$20,591	$133,776	$92,324	$65,664
Operating income (loss)	2,842	16,783	12,603	7,695	1,969	11,732	5,188	4,209	39,922	23,097	5,532
Net income (loss)	$30,132	$25,399	$3,034	$4,704	$26,996	$3,190	$7,866	$595	$63,269	$38,647	($18,791)
Net income (loss) per common share - basic (in dollars per share)	$0.29	$0.24	$0.03	$0.05	$0.29	$0.03	$0.09	$0.01	$0.64	$0.42	($0.20)
Net income (loss) - per common share - diluted (in dollars per share)	$0.28	$0.24	$0.03	$0.05	$0.29	$0.03	$0.08	$0.01	$0.62	$0.41	($0.20)

Benefit_Plans_Details

Benefit Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]
Contribution to 401(k) plan	$313,899	$284,865	$267,289
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	17,500	17,000
Employee contribution limit for employees of 50 years of age or older	$23,000	$23,000	$22,500

Hedging_Program_and_Derivative2

Hedging Program and Derivatives (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	bbl
Impact of derivative contracts on balance sheet [Abstract]
Derivative asset - current	$12,214	$85
Derivative asset - long-term	10,981	925
Derivative Assets	23,195	1,010
Derivative liability - current	13	2,728
Derivative liability - long-term	0	2,274
Derivative Liabilities	13	5,002
Commodity Price Derivatives [Member] | Derivative Asset - Current [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative asset - current	12,214	85
Commodity Price Derivatives [Member] | Derivative Asset - Long-Term [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative asset - long-term	10,981	925
Commodity Price Derivatives [Member] | Derivative Liability - Current [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative liability - current	13	2,728
Commodity Price Derivatives [Member] | Derivative Liability - Long-Term [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative liability - long-term	$0	$2,274
Oil - WTI [Member] | 2015 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Daily Volume (in Bbl)	1,045
Swap Price (in dollars per Bbl)	85.04
Oil - WTI [Member] | 2016 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Daily Volume (in Bbl)	948
Swap Price (in dollars per Bbl)	84.1
Oil - WTI [Member] | 2017 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Daily Volume (in Bbl)	493
Swap Price (in dollars per Bbl)	84.18
Oil - LLS [Member] | 2016 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Daily Volume (in Bbl)	0
Swap Price (in dollars per Bbl)	0
Oil - LLS [Member] | 2017 [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Daily Volume (in Bbl)	0
Swap Price (in dollars per Bbl)	0

Financial_Instruments_Details

Financial Instruments (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	$23,195	$1,010
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	13	5,002
Recurring Basis [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	23,195	1,010
Total Assets	23,195	1,010
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	13	5,002
Total Liabilities	13	5,002
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	0	0
Total Assets	0	0
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	0	0
Total Liabilities	0	0
Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	23,195	1,010
Total Assets	23,195	1,010
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	13	5,002
Total Liabilities	13	5,002
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	0	0
Total Assets	0	0
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	0	0
Total Liabilities	$0	$0

Discontinued_Operations_Detail

Discontinued Operations (Details) (Canadian Abraxas Petroleum, UCL, USD $)	10 Months Ended	12 Months Ended
	Oct. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Canadian Abraxas Petroleum, UCL
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale		$1,900,000
Revenue	1,200,000		2,000,000
Net loss	-600,000		-8,200,000
Disposal Group, Including Discontinued Operation, Classified Balance Sheet Disclosures [Abstract]
Current assets	252,000		213,000
Oil and gas properties - net	659,000		1,336,000
Other assets	0		91,000
Total Assets	911,000		1,640,000
Accounts payable	275,000		224,000
Accrued expenses	280,000		276,000
Total liabilities	555,000		500,000
Net assets of discontinued operation	$356,000		$1,140,000

Supplemental_Oil_and_Gas_Discl2

Supplemental Oil and Gas Disclosures (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized costs relating to oil and gas producing activities [Abstract]
Proved oil and gas properties	$716,922	$564,755
Unproved properties	0	0
Total	716,922	564,755
Accumulated depreciation, depletion, amortization and impairment	-423,819	-413,704
Net capitalized costs	293,103	151,051
Cost incurred in oil and gas property acquisition and development activities [Abstract]
Development costs	189,332	93,878	56,318
Exploration costs	0	0	0
Property acquisition costs	0	0	7,200
Unproved	0	0	989
Total	189,332	93,878	64,507
Results of operations for oil and gas producing activities [Abstract]
Revenues	134,883	94,275	68,499
Production costs	-38,146	-33,871	-31,419
Depreciation, depletion, and amortization	-42,945	-26,072	-22,767
Proved property impairment	0	-6,025	-19,774
General and administrative	-2,796	-3,350	-2,679
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$50,996	$24,957	($8,140)
Depletion per barrel of oil equivalent	20.39	16.59	15.59
Oil/NGL [Member]
Proved developed and undeveloped reserves [Abstract]
Balance	22,953,000	19,956,000	14,219,000
Revisions of previous estimates	3,718,000	999,000	1,574,000
Extensions and discoveries	8,648,000	10,746,000	5,809,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place			1,000
Sales of minerals in place	-620,000	-7,748,000	-850,000
Production	1,601,000	1,000,000	797,000
Balance	33,098,000	22,953,000	19,956,000
Proved Developed Reserves [Abstract]
Proved Developed Reserves	12,168,000	8,310,000	8,650,000
Proved Undeveloped Reserves [Abstract]
Proved Undeveloped Reserves	20,930,000	14,640,000	11,306,000
Proved Undeveloped Reserves (Volume), Period Increase (Decrease)	0
Natural Gas [Member]
Proved developed and undeveloped reserves [Abstract]
Balance	48,109,000	61,184,000	72,075,000
Revisions of previous estimates	7,383,000	-5,123,000	-7,470,000
Extensions and discoveries	6,893,000	3,610,000	6,983,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place			69,000
Sales of minerals in place	-3,614,000	-8,141,000	-6,376,000
Production	2,918,000	3,421,000	4,097,000
Balance	55,853,000	48,109,000	61,184,000
Proved Developed Reserves [Abstract]
Proved Developed Reserves	34,677,000	31,572,000	41,220,000
Proved Undeveloped Reserves [Abstract]
Proved Undeveloped Reserves	21,176,000	16,537,000	19,964,000
Oil Equivalents [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	4
Proved developed and undeveloped reserves [Abstract]
Balance	30,970,000	30,152,000	26,232,000
Revisions of previous estimates	4,950,000	145,000	328,000
Extensions and discoveries	9,797,000	11,348,000	6,973,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place, Energy			13,000
Sales of minerals in place	-1,223,000	-9,105,000	-1,913,000
Production	2,088,000	1,570,000	1,481,000
Balance	42,406,000	30,970,000	30,152,000
Proved Developed Reserves [Abstract]
Proved Developed Reserves	17,948,000	13,572,000	15,520,000
Proved Undeveloped Reserves [Abstract]
Proved Undeveloped Reserves	24,459,000	17,397,000	14,634,000
Productive Oil Equivalent Wells, Number of New Wells, Gross	20
TEXAS | Oil Equivalents [Member]
Proved Undeveloped Reserves [Abstract]
Productive Oil Equivalent Wells, Number of New Wells, Gross	10
NORTH DAKOTA | Oil Equivalents [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	1
Proved Undeveloped Reserves [Abstract]
Productive Oil Equivalent Wells, Number of New Wells, Gross	10
Gas and Oil Area, Undeveloped, Additional Down-Spaced Locations	28
Proved Undeveloped Reserves (Energy)	8
NORTH DAKOTA | Maximum [Member] | Oil Equivalents [Member]
Proved Undeveloped Reserves [Abstract]
Gas and Oil Area, Undeveloped, Gross, Feet Between Wells	1,320
NORTH DAKOTA | Minimum [Member] | Oil Equivalents [Member]
Proved Undeveloped Reserves [Abstract]
Gas and Oil Area, Undeveloped, Gross, Feet Between Wells	660

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, 2014		Dec. 31, 2013		Dec. 31, 2012
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	36 years
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	$2,988,464		$2,244,846		$1,784,920
Future production costs	-921,977		-754,722		-642,706
Future development costs	-557,782		-467,206		-328,554
Future income tax expense	-373,095		-244,394		-149,625
Future net cash flows	1,135,610		778,524		664,035
Discount	-623,053		-437,539		-385,890
Standardized Measure of discounted future net cash relating to proved reserves	512,557		340,985		278,145
Analysis of the changes in Standardized Measure [Roll Forward]
Standardized Measure, beginning of year	340,985		278,145		269,082
Sales and transfers of oil and gas produced, net of production costs	96,364		60,403		37,080
Net change in prices and development and production costs from prior year	150,504		169,969		60,710
Extensions, discoveries, and improved recovery, less related costs	147,275		156,456		73,236
Sales of minerals in place	-15,042		-125,533		-20,089
Purchased of minerals in place	0		0		131
Revisions of previous quantity estimates	74,390		2,930		3,355
Change in timing and other	-82,653		-62,861		-88,309
Change in future income tax expense	-40,636		-45,532		-9,799
Accretion of discount	34,098		27,814		26,908
Standardized Measure, end of year	$512,557		$340,985		$278,145
Oil and gas prices considered in standardized measure of discounted future net cash flows [Abstract]
Oil (in dollars per Bbl)	95.28	[1]	97.33	[1]	95.14	[1]
Gas (in dollars per MMbtu)	4.35	[2]	3.67	[2]	2.86	[2]
Oil (in dollars per Bbl)	87.11	[3]	95.9	[3]	88.26	[3]
Gas (in dollars per MMBtu)	5.15	[4]	3.65	[4]	2.61	[4]
NGL's (in dollars per Bbl)	37.91	[5]	31.98	[5]	36.76	[5]
[1]	The quoted oil price for the year ended December 31 of each year, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2012, 2013 and 2014.
[2]	The quoted gas price for the year ended December 31, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2012, 2013 and 2014.
[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.