Abraxas Petroleum (AXAS) 10-K 16 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 10, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	ABRAXAS PETROLEUM CORP
Entity Central Index Key	867,665
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		163,844,255
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 141,714,282

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 0	$ 3,540
Accounts receivable:
Joint owners - net	677	1,552
Oil and gas production sales	11,595	6,713
Other	1,252	1,241
Total accounts receivable	13,524	9,506
Derivative assets	54	18,902
Assets held for sale	9,685	0
Other current assets	676	726
Total current assets	23,939	32,674
Oil and gas properties, full cost method of accounting:
Proved	794,634	787,683
Other property and equipment	38,569	41,444
Total	833,203	829,127
Less accumulated depreciation, depletion, amortization and impairment	(696,892)	(604,289)
Total property and equipment, net	136,311	224,838
Deferred financing fees, net	818	1,642
Derivative asset	0	8,463
Other assets	580	255
Total assets	161,648	267,872
Current liabilities:
Accounts payable	18,397	24,825
Joint interest oil and gas production payable	8,937	7,177
Accrued interest	44	115
Other accrued expenses	571	622
Derivative liability	2,382	0
Current maturities of long-term debt	786	2,330
Total current liabilities	31,117	35,069
Long-term debt – less current maturities	96,616	138,402
Other liabilities	157	257
Derivative liability	6,630	0
Future site restoration	8,623	9,679
Total liabilities	143,143	183,407
Commitments and contingencies
Stockholders’ Equity:
Preferred stock, par value $.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding	0	0
Common stock, par value $.01 per share – authorized 200,000,000 shares; issued and outstanding 106,346,678 and 135,094,017, respectively	1,351	1,063
Additional paid-in capital	343,982	313,852
Accumulated deficit	(326,828)	(230,450)
Total stockholders’ equity	18,505	84,465
Total liabilities and stockholders’ equity	$ 161,648	$ 267,872

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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	106,346,001
Common stock, shares outstanding (in shares)	106,186,678	106,346,001

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil and gas production revenues	$ 56,493	$ 67,002	$ 133,701
Other	62	28	75
Total revenue	56,555	67,030	133,776
Operating costs and expenses:
Lease operating	18,205	23,074	25,875
Production taxes	5,454	6,679	11,462
Rig expense	664	0	0
Depreciation, depletion, and amortization	24,431	38,721	43,139
Proved property impairment	67,626	128,573	0
General and administrative (including stock-based compensation of $2,703, $3,912 and $3,194, respectively)	13,562	11,788	13,378
Operating expenses	129,942	208,835	93,854
Operating income (loss)	(73,387)	(141,805)	39,922
Other (income) expense:
Interest income	(1)	(2)	(2)
Interest expense	4,319	3,906	2,570
Amortization of deferred financing fees	1,019	643	934
(Gain) on sale of properties	(374)	0	0
(Gain) loss on derivative contracts	18,028	(19,301)	(25,237)
Other	0	318	(7)
Total other (income) expense	22,991	(14,436)	(21,742)
Income (loss) from continuing operations before income tax	(96,378)	(127,369)	61,664
Income tax benefit	0	279	287
Net income (loss) from continuing operations	(96,378)	(127,090)	61,951
Net income (loss) from discontinued operations - net of tax	0	(20)	1,318
Net income (loss)	$ (96,378)	$ (127,110)	$ 63,269
Net income (loss) per common share - basic
Continuing operations (in dollars per share)	$ (0.79)	$ (1.21)	$ 0.63
Discontinued operations (in dollars per share)	0	0	0.01
Total (in dollars per share)	(0.79)	(1.21)	0.64
Net income (loss) per common share - diluted
Continuing operations (in dollars per share)	(0.79)	(1.21)	0.61
Discontinued operations (in dollars per share)	0	0	0.01
Total (in dollars per share)	$ (0.79)	$ (1.21)	$ 0.62
Weighted Average Number of Shares Outstanding, Basic and Diluted [Abstract]
Weighted Average Number of Shares Outstanding, Basic	122,132	104,605	98,835
Weighted Average Number of Shares Outstanding, Diluted	122,132	104,605	101,468

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating costs and expenses:
Stock-based compensation	$ 3,194	$ 3,912	$ 2,703

CONSOLIDATED STATEMENTS OF OTHE

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (96,378)	$ (127,110)	$ 63,269
Other comprehensive income (loss):
Foreign currency translation adjustment	0	0	607
Other comprehensive income (loss)	0	0	607
Comprehensive income (loss)	$ (96,378)	$ (127,110)	$ 63,876

CONSOLIDATED STATEMENTS OF STOC

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, 2013	$ 86,906,000	$ 929,000	$ 253,193,000	$ (166,609,000)	$ (607,000)
Balance (in shares) at Dec. 31, 2013		92,906,049
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	63,269,000	$ 0	0	63,269,000	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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(127,110,000)	$ 0	0		0
Stock issuance	53,755,000	$ 115,000	53,640,000
Stock issuance (in shares)		11,500,000
Stock-based compensation	3,912,000	$ 0	3,912,000	0	0
Stock options exercised	168,000	$ 1,000	167,000	0	0
Stock options exercised (in shares)		164,400
Restricted stock issued, net of cancellations	0	$ 0	0	0	0
Restricted stock issued, net of cancellations (in shares)		(5,077)
Balance at Dec. 31, 2015	$ 84,465,000	$ 1,063,000	313,852,000	(230,450,000)	0
Balance (in shares) at Dec. 31, 2015	106,346,001	106,346,001
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (96,378,000)	$ 0	0		0
Stock-based compensation	3,194,000	0	3,194,000	0	0
Stock options exercised	49,000	$ 1,000	48,000	0	0
Stock options exercised (in shares)		55,716
Restricted stock issued, net of cancellations	0	$ 0	0	0	0
Restricted stock issued, net of cancellations (in shares)		(98,802)
Balance at Dec. 31, 2016	$ 18,505,000	$ 1,351,000	$ 343,982,000	$ (326,828,000)	$ 0
Balance (in shares) at Dec. 31, 2016	106,186,678	135,094,017

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Activities
Net income (loss)	$ (96,378)	$ (127,110)	$ 63,269
Net income (loss) from discontinued operations	0	(20)	1,318
Net income (loss) from continuing operations	(96,378)	(127,090)	61,951
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Gain) on sale of properties	(374)	0	0
Net (gain) loss on derivative contracts	18,028	(19,301)	(25,237)
Derivative contract settlements	1,790	9,495	361
Monetization of derivative contracts	14,370	4,610	152
Depreciation, depletion, and amortization	24,431	38,721	43,139
Proved property impairment	67,626	128,573	0
Accretion of future site restoration	491	565	559
Amortization of deferred financing fees	1,019	643	934
Stock-based compensation	3,194	3,912	2,703
Non-cash compensation	40	0	0
Changes in operating assets and liabilities:
Accounts receivable - net of allowance	(4,018)	12,097	11,881
Other assets and liabilities	627	1,466	(2,717)
Accounts payable	(3,535)	(45,970)	1,596
Accrued expenses	(439)	(722)	(860)
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	26,872	6,999	94,462
Cash Provided by (Used in) Operating Activities, Discontinued Operations	0	(20)	1,741
Net cash provided by continuing operations	26,872	6,979	96,203
Investing Activities
Capital expenditures, including purchases and development of properties	(31,663)	(69,391)	(192,799)
Proceeds from the sale of oil and gas properties	13,570	138	5,999
Proceeds from the sale of non-oil and gas properties	4,022	0	0
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	(14,071)	(69,253)	(186,800)
Cash Provided by (Used in) Investing Activities, Discontinued Operations	0	0	332
Net cash used in continuing operations	(14,071)	(69,253)	(186,468)
Financing Activities
Proceeds from exercise of stock options	49	168	255
Proceeds from issuance of common stock, net of offering costs	27,135	0	53,755
Proceeds from long-term borrowings	22,000	68,007	82,000
Payments on long-term borrowings	(65,330)	(6,064)	(47,143)
Deferred financing fees	(195)	(69)	(1,010)
Net Cash Provided by (Used in) Financing Activities, Continuing Operations	(16,341)	62,042	87,857
Cash Provided by (Used in) Financing Activities, Discontinued Operations	0	0	975
Net cash provided by (used in) continuing operations	(16,341)	62,042	88,832
Decrease in cash	(3,540)		(1,433)
Cash and cash equivalents at beginning of year	3,540	3,772	5,205
Cash and cash equivalents at end of year	0	3,540	3,772
Supplemental disclosure of cash flow information:
Interest Paid	3,899	3,298	1,970
Income taxes paid	0	0	0
Non-Cash Investing Activities:
Asset retirement obligation cost and liabilities	(285)	(30)	(198)
Asset retirement obligations associated with property acquisitions and dispositions	$ (1,832)	$ 410	$ (406)

Organization and Significant Ac

Organization and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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 South Texas. 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. The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, asset retirement obligations, accrued oil and gas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates. Concentration of Credit Risk Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties. The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality. Cash and Equivalents Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less. Accounts Receivable Accounts receivable are reported net of an allowance for doubtful accounts of approximately $296,000 and $228,000 at December 31, 2015 and 2016, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible. Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development and production of oil and gas with all of the Company’s operational activities having been conducted in the U.S. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S. 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% , 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. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. For the year ended December 31, 2015, our capitalized cost of oil and gas properties exceeded the present value of our estimated proved reserves by $128.6 million , resulting in the recognition of a proved property impairment of $128.6 million . As of December 31, 2016, our capitalized cost of oil and gas properties did not exceed the present value of our estimated proved reserves. However, we incurred proved property impairments in each of the first three quarters of 2016 in the amount of $67.6 million . The impairment calculations did not consider the impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. 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. Assets Held for Sale The Company entered into an agreement to sell certain non-core assets in late 2016 that are presented separately as “ Assets held for sale" in the consolidated balance sheet at December 31, 2016. Assets held for sale were measured at the lower of its carrying amount or estimated fair value less costs to sell. The amount allocated to assets held for sale were recorded as a reduction to the full cost pool. The transaction closed and proceeds were received on January 3, 2017. See Note 14. Subsequent Events. 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 unweighted average 12 month first-day-of-month pricing. 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 and three way collars, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could, result in overhedged volumes. All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in its 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, the Company does not account for its derivative instruments as cash flow hedges for financial reporting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts in the Consolidated Statements of Operations. 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 Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. 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, 2014, 2015 and 2016, stock-based compensation was approximately $2.7 million , $3.9 million and $3.2 million , respectively. 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 fair value of a liability for an asset's retirement obligation is 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. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates. The following table summarizes the Company’s asset retirement obligations during the two years ended December 31: 2015 2016 (in thousands) Beginning asset retirement obligation $ 9,495 $ 9,679 New wells placed on production and other 307 119 Deletions related to property disposals and plugging costs (793 ) (1,832 ) Accretion expense 565 491 Revisions 105 166 Ending asset retirement obligation $ 9,679 $ 8,623 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, 2015 and 2016. During 2014, two purchasers accounted for 62% of oil and gas revenues. During 2015, one purchaser accounted for 54% of oil and gas revenues. During 2016, two purchasers accounted for 71% 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 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 with respect 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. Therefore, we have established a valuation allowance of $137.8 million for deferred tax assets at December 31, 2016. Accounting for Uncertainty in Income Taxes 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. The Company had no uncertain income tax positions as of December 31, 2016. New Accounting Standards and Disclosures I n May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date ("ASU 2015-14"). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. We are currently evaluating the impact, if any, of the standard by comparing historical accounting policies and practices to the new standard and will evaluate guidance from accounting regulatory agencies as it becomes available. The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835) : Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective beginning January 1, 2016 and have been applied using the retrospective approach. These ASUs did not have a material impact on Abraxas's consolidated financial statements and related disclosures. In August 2015, the FASB issued ASU 2015-15, “ Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ”, codifies an SEC staff announcement that entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets. The ASU clarifies that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The ASU is effective immediately for both public business entities and non-public entities. Abraxas has elected to follow this presentation guidance. The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. We have adopted and applied this standard using the retrospective approach. This ASU did not have an impact on our consolidated financial statements and related disclosures. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) : Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment is effective. In February 2016, the FASB issued ASU 2016-02 “ Leases, " which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718) : Improvements to Employee Share-Based Payment Accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's consolidated financial statements. In August 2016, FASB issued amended guidance to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The amendments provide guidance on the following eight specific cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods ending after December 15, 2016, and to annual and interim periods thereafter. Earlier adoption is permitted. The Company has adopted this guidance as of December 31, 2016 and there is no impact on its consolidated financial statements.

Divestiture of Non-Core Propert

Divestiture of Non-Core Properties	12 Months Ended
	Dec. 31, 2016
Divestiture of Non Core Properties [Abstract]
Divestiture of Non-Core Properties	Divestiture of Properties Beginning in the third quarter of 2012 and continuing through the present, 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 and Permian Basin. In total the Company divested a number of non-core assets for total net proceeds of $169.9 million from 2012-2016. The net proceeds were used to repay outstanding indebtedness under the Company's credit facility, for capital expenditures and general corporate purposes.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The following is a description of the Company’s debt as of December 31, 2015 and 2016, respectively: December 31, December 31, (In thousands) Senior secured credit facility $ 134,000 $ 93,000 Rig loan agreement 2,620 535 Real estate lien note 4,112 3,867 140,732 97,402 Less current maturities (2,330 ) (786 ) $ 138,402 $ 96,616 Maturities of long-term debt are as follows: Year ending December 31, (In thousands) 2017 $ 786 2018 93,261 2019 273 2020 285 2021 297 Thereafter 2,500 $ 97,402 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, 2016, $93.0 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, 2016, we had a borrowing base of $115.0 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 next redetermination will be effective on April 1, 2017. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge additional oil and gas properties or other assets as collateral. We do not currently have any substantial unpledged assets and we may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause us to fail to be in compliance with the financial covenants described below. 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, 2016, the interest rate on the credit facility was 3.27% 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. The collateral is required to include properties comprising of least 90% of the PV-10 of our proven reserves. We have also granted our lenders a security interest in our headquarters building and a ranch that we own in West Texas. 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, Derivatives and Hedging, and ASC 410-20 Asset Retirement Obligations, 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 and obligations with respect to surety bonds and derivative contracts . At December 31, 2016 we were in compliance with all of our debt covenants. As of December 31, 2016, the interest coverage ratio was 10.49 to 1.00, the total debt to EBITDAX ratio was 2.32 to 1.00, and our current ratio was 1.64 to 1.00. The credit facility contains a number of other 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 certain additional covenants including: • 100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and • If the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility. 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. As of December 31, 2016 we were in compliance with all of these conditions. 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 . As of December 31, 2015 and 2016, $2.6 million and $0.5 million , respectively, were outstanding under the rig loan agreement. This loan was paid in full in March 2017. 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, 2015 and 2016, $4.1 million and $3.9 million , respectively, were outstanding on the note.

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2016
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, 2015 2016 Years (In thousands) Oil and gas properties — $ 787,683 $ 794,634 Equipment and other 3-39 18,866 15,227 Drilling rig 15 22,578 23,342 829,127 833,203 Accumulated depreciation, depletion, amortization and impairment (604,289 ) (696,892 ) Net Property and Equipment $ 224,838 $ 136,311

Stock-based Compensation, Optio

Stock-based Compensation, Option Plans and Warrants	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based Compensation, Option Plans and Warrants	Stock-Based Compensation and Option Plans The Company’s Amended and Restated 2005 Employee Long-Term Equity Incentive Plan reserves 10.6 million shares of Abraxas common stock, subject to adjustment following certain events. Awards may be in options or shares of restricted stock. 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. Stock Options The Company 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 2014, 2015 and 2016: 2014 2015 2016 Weighted average value per option granted during the period $ 2.44 $ 2.37 $ 0.68 Assumptions: Forfeiture rate (1) 4.2 % 4.5 % 4.2 % Expected dividend yield (2) — % — % — % Volatility (3) 80.7 % 81.1 % 71.1 % Risk free interest rate (4) 2.05 % 1.92 % 1.72 % Expected life (years) (5) 6.6 7.0 7.0 Fair value of options granted (in thousands) $ 2,666 $ 3,792 $ 2,307 ______________________ (1) The estimated future forfeiture rate is based on the Company’s historical forfeiture rate. (2) The dividend yield is based on the fact the Company does not pay any dividends. (3) The volatility is based on the historical volatility of our stock for a period approximating the expected life. (4) The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. (5) The expected life was derived based on a weighting between (a) the Company’s historical exercise and forfeiture activity and (b) the average midpoint between vesting and the contractual term. The Company grants options to its officers, directors, and other employees under various stock option and incentive plans. The following table is a summary of the Company’s stock option activity for the three years ended December 31: Options (000s) Weighted average exercise price Weighted average remaining life Intrinsic value per share 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 Granted 1,601 3.22 Exercised (164 ) 1.03 Forfeited/Expired (514 ) 4.36 Options outstanding December 31, 2015 6,808 $ 2.89 Granted 2,265 1.02 Exercised (83 ) 1.40 Forfeited/Expired (836 ) 2.84 Options outstanding December 31, 2016 8,154 $ 2.39 6.39 1.70 Exercisable at end of year 4,808 4.90 1.93 Other information pertaining to the Company’s stock option activity for the three years ended December 31: 2014 2015 2016 Weighted average grant date fair value of stock options granted (per share) $ 2.44 $ 2.37 $ 0.68 Total fair value of options vested (000’s) $ 1,718 $ 2,035 $ 2,776 Total intrinsic value of options exercised (000’s) $ 932 $ 124 $ 39 As of December 31, 2016, the total compensation cost related to non-vested awards not yet recognized was approximately $2.9 million , which will be recognized in 2017 through 2020. For the years ended December 31, 2014, 2015 and 2016, we recognized $1.8 million , $2.4 million and $2.0 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, 2016: Options outstanding Exercisable Number outstanding Weighted average remaining life Weighted average exercise price Number exercisable Weighted average remaining life Weighted average exercise price 0.97 - 1.99 3,462,042 6.7 $ 1.23 1,595,042 3.8 $ 1.52 2.00 - 2.99 1,240,350 5.2 $ 2.35 1,102,063 5.0 $ 2.35 3.00 - 3.99 2,765,633 7.0 $ 3.29 1,438,408 6.3 $ 3.41 4.00 - 4.99 585,750 3.6 $ 4.56 574,750 3.6 $ 4.56 5.00 - 5.99 99,000 7.4 $ 5.39 97,500 7.4 $ 5.38 6.00 - 6.28 1,000 7.5 $ 6.28 500 7.5 $ 6.28 8,153,775 4,808,263 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, 2016, the total compensation cost related to non-vested awards not yet recognized was approximately $1.9 million , which will be recognized in 2017 through 2020. For the years ended December 31, 2014, 2015 and 2016, we recognized $0.9 million , $1.5 million and $1.2 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, 2016: Number of Shares Weighted average grant date fair value 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 Granted — — Vested/Released (127,729 ) 3.38 Forfeited (5,077 ) 2.56 Unvested December 31, 2015 1,643,284 $ 3.44 Granted — — Vested/Released (52,017 ) 2.40 Forfeited (98,802 ) 3.63 Unvested December 31, 2016 1,492,465 $ 3.47 Director Stock Awards The 2005 Directors Plan (as amended and restated) reserves 1.9 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 25,000 shares of Abraxas common stock, for participation in board and committee meetings during the previous calendar year. The maximum annual award for any one person is 100,000 shares of Abraxas common stock or options for common stock. If options, as opposed to shares, are awarded, the exercise price shall be no less than 100% of the fair market value on the date of the award while the option terms and vesting schedules are at the discretion of the committee. In 2014 and 2015 directors were paid a retainer fee of $40,000 . Beginning in 2016, the retainer fee was reduced by 20% and paid one half in cash and one half in Abraxas common stock. The retainer fee for 2016 was $32,000 . At December 31, 2016, the Company had approximately 9.0 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, 2016
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, 2014 2015 2016 (In thousands) Deferred tax liabilities: Hedge contracts $ 8,114 $ 9,578 $ — Assets held for sale — — 3,390 Other 4,458 4,042 4,431 Total deferred tax liabilities 12,572 13,620 7,821 Deferred tax assets: U.S. full cost pool 3,352 35,689 48,436 Capital loss carryforward 12,325 7,767 7,361 Depletion carryforward 4,936 5,558 5,216 U.S. net operating loss carryforward 50,941 67,531 80,670 Alternative minimum tax credit 1,104 757 757 Hedge contracts — — 3,135 Total deferred tax assets 72,658 117,302 145,575 Valuation allowance for deferred tax assets (60,086 ) (103,682 ) (137,754 ) Net deferred tax assets 12,572 13,620 7,821 Net deferred tax $ — $ — $ — Significant components of the provision (benefit) for income taxes are as follows: Years ended December 31, 2014 2015 2016 (In thousands) Current: Federal $ (276 ) $ (242 ) $ — State (11 ) (37 ) — $ (287 ) $ (279 ) $ — Deferred: Federal $ — $ — $ — $ — $ — $ — At December 31, 2016, the Company had, subject to the limitation discussed below, $230.5 million of net operating loss carryforwards for U.S. tax purposes. The U.S. federal loss carryforward will expire in varying amounts from 2022 through 2036 , 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, 2016, 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. Therefore, the Company has established a valuation allowance of $60.1 million at December 31, 2014, $103.7 million at December 31, 2015 and $137.8 million at December 31, 2016. The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is: Years ended December 31, 2014 2015 2016 (In thousands) Tax (expense) benefit at U.S. statutory rates (35%) $ (22,044 ) $ 44,586 $ 33,732 (Increase) decrease in deferred tax asset valuation allowance 15,480 (43,596 ) (34,072 ) Alternative minimum tax — 568 — Rate differential for non US income (39 ) — — State income taxes — — — Accrual of prior year federal taxes (2009 and 2013) 287 37 — Permanent differences (950 ) (1,371 ) (1,133 ) Return to provision estimate revision 4,562 — 1,473 Tax benefit related to the sale of Canadian subsidiary 3,501 — — Increase in asset for partnership distribution — — — Other (510 ) 55 — $ 287 $ 279 $ — During 2016, the Company increased deferred tax assets by $28.3 million primarily related to increases in the full cost pool assets and net operating loss carryforward. The deferred tax assets were fully offset by a valuation allowance which was reduced at the same time. As of December 31, 2016, 2015 and 2014, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2012 through 2016 remain open to examination by the tax jurisdictions to which the Company is subject.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
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 2014, 2015 and 2016, rent expense incurred for the Dickinson, North Dakota office was $26,265 , $27,165 , and $27,840 , respectively. The lease expires on October 31, 2018. Rent expense incurred for the Lusk, Wyoming office for 2014, 2015 and 2016 was $9,000 for each year. The lease expires on December 31, 2018. Rent expense for the Denver Colorado office for 2014, 2015 and 2016 was $14,554 , $15,601 and $15,766 , respectively. The lease expires on December 31, 2017. 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, 2016, 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, 2016
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: 2014 2015 2016 (In thousands, except per share data) Numerator: Net income (loss) from continuing operations $ 61,951 $ (127,090 ) $ (96,378 ) Net income (loss) from discontinued operations 1,318 (20 ) — $ 63,269 $ (127,110 ) $ (96,378 ) Denominator: Denominator for basic earnings per share – weighted-average common shares outstanding 98,835 104,605 122,132 Effect of dilutive securities: Stock options and restricted shares 2,633 — — Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares 101,468 104,605 122,132 Net income (loss) per common share - basic Continuing operations $ 0.63 $ (1.21 ) $ (0.79 ) Discontinued operations 0.01 — — $ 0.64 $ (1.21 ) $ (0.79 ) Net income (loss) per common share - diluted Continuing operations $ 0.61 $ (1.21 ) $ (0.79 ) Discontinued operations 0.01 — — $ 0.62 $ (1.21 ) $ (0.79 ) 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, 2015 and 2016, 624 and 1,635, respectively, of 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 year ended December 31, 2014.

Quarterly Results of Operations

Quarterly Results of Operations (Unaudited)	12 Months Ended
	Dec. 31, 2016
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, 2015 and 2016 are as follows: 1 st Quarter 2 nd Quarter 3 rd Quarter 4 th Quarter (In thousands, except per share data) Year Ended December 31, 2015 Net revenue $ 18,661 $ 18,944 $ 16,077 $ 13,348 Operating loss $ (4,535 ) $ (1,531 ) $ (63,438 ) $ (72,301 ) Net loss $ (718 ) $ (6,601 ) $ (52,372 ) $ (67,419 ) Net loss per common share – basic $ (0.01 ) $ (0.06 ) $ (0.50 ) $ (0.64 ) Net loss per common share – diluted $ (0.01 ) $ (0.06 ) $ (0.50 ) $ (0.64 ) Year Ended December 31, 2016 Net revenue $ 9,564 $ 11,008 $ 13,976 $ 22,007 Operating (loss) income $ (40,143 ) $ (31,898 ) $ (4,952 ) $ 3,606 Net loss $ (40,880 ) $ (46,937 ) $ (3,260 ) $ (5,301 ) Net loss per common share – basic $ (0.39 ) $ (0.40 ) $ (0.02 ) $ (0.04 ) Net loss per common share – diluted $ (0.39 ) $ (0.40 ) $ (0.02 ) $ (0.04 )

Benefit Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Benefit Plans	Benefit Plans The Company has a defined contribution plan (401(k) plan) covering all eligible employees. In 2014, 2015 and 2016, in accordance with the safe harbor provisions of the plan, the Company contributed $313,899 , $347,632 and $256,309 , 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% . Each 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 2014 was $17,500 for employees under the age of 50 and $23,000 for employees 50 years of age or older. The 2015 and 2016 employee contribution limit was $18,000 for employees under the age of 50 and $24,000 for employees 50 years of age or older.

Hedging Program and Derivatives

Hedging Program and Derivatives	12 Months Ended
	Dec. 31, 2016
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, 2016: Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps 2017 2,401 $ 54.53 2018 1,796 $ 47.48 2019 1,200 $ 54.54 Basis Swap 2017 500 $ 0.65 Collar contracts: Gas Contract Periods Daily Volume (Mcf) Floor (Long Put) Ceiling (Short Call) 2017 5,000 $ 3.00 $ 3.90 The following table illustrates the impact of derivative contracts on the Company’s balance sheet: Fair Value of Derivative Instruments as of December 31, 2015 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 $ 18,902 Derivatives – current $ — Commodity price derivatives Derivatives – long-term 8,463 Derivatives – long-term — $ 27,365 $ — Fair Value of Derivative Instruments as of December 31, 2016 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 $ 54 Derivatives – current $ 2,382 Commodity price derivatives Derivatives – long-term — Derivatives – long-term 6,630 $ 54 $ 9,012 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, 2016
Fair Value Disclosures [Abstract]
Financial Instruments	Financial Instruments There is 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, 2015 and 2016, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2015 Assets: NYMEX Fixed Price Derivative contracts $ — $ 21,731 $ — $ 21,731 NYMEX Collars — — 5,634 5,634 Total Assets $ — $ 21,731 $ 5,634 $ 27,365 Liabilities: NYMEX Fixed Price Derivative contracts $ — $ — $ — $ — Total Liabilities $ — $ — $ — $ — Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2016 Assets: NYMEX Fixed Price Derivative contracts $ — $ 35 $ — $ 35 NYMEX Collars — — 19 19 Total Assets $ — $ 35 $ 19 $ 54 Liabilities: NYMEX Fixed Price Derivative contracts $ — $ 8,759 $ — $ 8,759 NYMEX Collars/basis differential swaps $ — $ — $ 253 $ 253 Total Liabilities $ — $ 8,759 $ 253 $ 9,012 The Company’s derivative contracts at December 31, 2016 consist of NYMEX-based fixed price commodity swaps, basis swaps and NYMEX collars. 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. The fair value of the collar instruments and the basis swaps are based on inputs that are not as observable as the fixed price swaps. In addition to the actively quoted market price, variables such as time value, volatility and other unobservable inputs are used. Accordingly, these instruments have been classified as Level 3. Additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the year ended December 31, 2016. (In thousands) Unobservable inputs at December 31, 2015 $ 5,634 Changes in market value (2,385 ) Settlements during the period (3,483 ) Unobservable inputs at December 31, 2016 $ (234 ) Nonrecurring Fair Value Measurements The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. As it relates to the Company, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 1. 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, 2016
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 was $2.0 million . Canadian Abraxas net loss, reported in discontinued operations for the ten months ended October 31, 2014 was $0.6 million .

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event In January 2017, the Company closed on the sale of non-core oil and gas properties in Wyoming. Net proceeds of $10.6 million , $1.1 million of which was received in 2016, were used to reduce amounts outstanding under the Company's credit facility. These assets are presented as " Assets held for sale" in the consolidated balance sheet as of December 31, 2016 at the lower of its carrying amount or estimated fair value less costs to sell. In January 2017, the Company completed the sale of 28.8 million shares of common stock. Net proceeds of approximately $65.3 million were used to reduce amounts outstanding under the Company's credit facility. In March 2017, the Company repaid the Rig Loan in full.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	Supplemental Oil and Gas Disclosures (Unaudited) Information in the following tables is inclusive of Canadian operations through October 2014, which 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 “Disclosures about Oil and Gas Producing Activities.” Capitalized costs relating to oil and gas producing activities are as follows: Years Ended December 31 2015 2016 (In thousands) Proved oil and gas properties $ 787,683 $ 794,634 Unproved properties — — Total 787,683 794,634 Accumulated depreciation, depletion, amortization and impairment (590,432 ) (680,861 ) Net capitalized costs $ 197,251 $ 113,773 Cost incurred in oil and gas property acquisition and development activities are as follows: Years Ended December 31 2014 2015 2016 (In thousands) Development costs $ 189,322 $ 68,631 $ 18,262 Exploration costs — — 12,529 Property acquisition costs — — — Unproved — — — $ 189,322 $ 68,631 $ 30,791 The results of operations for oil and gas producing activities, inclusive of discontinued operations, for the three years ended December 31, 2014, 2015 and 2016 are as follows: Years Ended December 31, 2014 2015 2016 (In thousands) Revenues $ 133,701 $ 67,002 $ 56,493 Production costs (37,337 ) (29,753 ) (23,659 ) Depreciation, depletion, and amortization (42,945 ) (38,040 ) (22,803 ) Proved property impairment — (128,573 ) (67,626 ) Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) $ 53,419 $ (129,364 ) $ (57,595 ) Depletion rate per barrel of oil equivalent $ 20.39 $ 17.44 $ 10.08 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, 2014, 2015, and 2016. 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 unweighted 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. The following is a summary of the changes to the Company’s proved reserves that occurred during 2016: Revisions to prior estimates : An increase of 5,005 MBoe of reserves was attributed to the Company’s Bakken and Three Forks proved undeveloped locations in McKenzie County, ND, due to continuing improvement in its producing well production results. Well results improved as a result of the application of optimized completion methods. Similarly, reserves for the Company’s Bakken and Three Forks producing wells increased by 1,360 MBoe of net producing reserves due to improved performance. On the other hand, projections for the Hedgehog State 16-2H producing well and its two related proved undeveloped locations in the Porcupine Field, Campbell County, WY, decreased by 670 MBoe of net reserves due to the under-performance of the Hedgehog State 16-2H. There was also a reduction in this category of 2,271 MBoe attributable to shortened economic life calculations at the lower commodity pricing. Extensions, discoveries and other additions : The Company added the Caprito 99 302H as a new Wolfcamp producing well in Ward County, TX, accounting for 449 MBoe of net producing reserves. It also added five new proved undeveloped Wolfcamp locations offsetting this new producer accounting for 805 MBoe of net undeveloped reserves. The Company also developed a new Austin Chalk producer in Atascosa County, TX, which accounted for 265 MBoe of net producing reserves. Further, the Company added eight new proved undeveloped Bakken/Three Forks locations on non-operated units in McKenzie County, ND, accounting for 18 MBoe of net undeveloped reserves. These locations were added in response to operator well proposals. Sales: The Company sold all its holdings in the Portilla Field in San Patricio County, TX, and in the Brooks Draw Field in Converse County, WY, during 2016. These sales accounted for 1,232 MBoe of net proved reserves. Production: The Company produced 2,262 MBoe of net reserves during 2016. The following is a summary of the changes to the Company’s proved reserves that occurred during 2015 : Revisions of prior estimates : A total of 48 proved locations accounting for approximately 7.9 net MMBoe of reserves were dropped from the report in 2015 due to lack of economic viability at the lower commodity pricing applied of which 42 were in the undeveloped category. Most significant of these were 38 South Texas Eagle Ford locations representing approximately 7,717 MBoe of net reserves. There was also a reduction of 614 net MBoe attributable to shortened economic life calculations at lower commodity pricing which were partially offset by an increase of 600 net MBoe in the Company’s Bakken/Three Forks undeveloped locations due to better-than-anticipated production. There were also reduction in this category of 1.8 MMBoe of net reserves attributable to shortened economic life calculations at the lower commodity pricing and 1.6 MMBoe of net reserves attributable to lower than anticipated production performance in various wells. Extensions, discoveries and other additions: The Company added 28 new proved undeveloped Bakken locations during 2015 on the Company’s prospect acreage in McKenzie County, North Dakota, accounting for approximately 6.5 MMBoe of net reserves, 20 of which accounting for 4.9 net MMBoe, were for the Three Forks (2 nd Bench) which were proved by local development activity in that reservoir during the year. There were also 8 other cases in the Bakken/Three Forks, accounting for 1.6 net MMBoe, which were added because the Company gained operational control of the Yellowstone Unit resulting in the Company developing the properties in accordance with its normal well spacing pattern. The Company also gained proved undeveloped reserves of approximately 1.3 net MMBOE, due to the change in classification of 21 probable and possible undeveloped Bakken cases into the proved category. This change was warranted by local well development in the specific local areas during 2015. The Company also added 6 new Montoya proved undeveloped locations on the Company’s prospect acreage in Ward County, Texas, accounting for 6.5 MMBOE of net reserves. These locations were added based on the performance of existing Montoya producers on the subject acreage. Sales: During 2015, the Company sold properties accounting for 43 net MBoe of reserves. Production: During 2015, the Company produced 2,181 of net MBoe of reserves Oil NGL Gas Oil Equivalents (MBbl) (MBbl) (MMcf) (MBoe) Proved developed and undeveloped reserves: (in thousands) Balance at December 31, 2013 20,915 2,038 48,109 30,970 Revisions of previous estimates 2,697 1,021 7,383 4,950 Extensions and discoveries 7,780 868 6,893 9,797 Sales of minerals in place (608 ) (12 ) (3,614 ) (1,223 ) Production (1,394 ) (207 ) (2,918 ) (2,088 ) Balance at December 31, 2014 29,390 3,708 55,853 42,406 Revisions of previous estimates (9,485 ) (505 ) (8,002 ) (11,324 ) Extensions and discoveries 5,679 3,591 30,372 14,332 Sales of minerals in place (13 ) — (181 ) (43 ) Production (1,440 ) (238 ) (3,015 ) (2,181 ) Balance at December 31, 2015 24,131 6,556 75,027 43,190 Revisions of previous estimates 1,379 2,300 (1,537 ) 3,424 Extensions and discoveries 1,183 157 1,179 1,537 Sales of minerals in place (1,112 ) (6 ) (680 ) (1,232 ) Production (1,372 ) (363 ) (3,160 ) (2,262 ) Balance at December 31, 2016 24,209 8,644 70,829 44,657 Total Oil NGL Gas Oil Equivalents (MBbl) (MBbl) (MMcf) (MBoe) (In thousands) Proved Developed Reserves: December 31, 2014 10,162 2,006 34,677 17,948 December 31, 2015 10,022 1,956 31,298 17,194 December 31, 2016 7,818 2,568 27,792 15,018 Proved Undeveloped Reserves: December 31, 2014 19,228 1,702 21,176 24,459 December 31, 2015 14,109 4,599 43,729 25,996 December 31, 2016 16,391 6,076 43,037 29,639 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, 2014, 2015 and 2016. The following information has been prepared in accordance with SEC rules and accounting standards based on the 12 -month first-day-of-the-month unweighted 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 2016, the standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year. The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. All reports by DeGolyer and MacNaughton were developed utilizing studies performed by DeGolyer and MacNaughton and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers. The report of DeGolyer and MacNaughton dated February 13, 2017, 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, 2014, 2015 and 2016 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 38 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, 2014, 2015 and 2016: Years Ended December 31, 2014 2015 2016 (In thousands) Future cash inflows $ 2,988,464 $ 1,241,334 $ 999,716 Future production costs (921,977 ) (438,784 ) (357,917 ) Future development costs (557,782 ) (338,316 ) (267,836 ) Future income tax expense (373,095 ) — — Future net cash flows 1,135,610 464,234 373,963 Discount (623,053 ) (266,983 ) (213,363 ) Standardized Measure of discounted future net cash relating to proved reserves $ 512,557 $ 197,251 $ 160,600 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, 2014 2015 2016 (In thousands) Standardized Measure, beginning of year $ 340,985 $ 512,557 $ 197,251 Sales and transfers of oil and gas produced, net of production costs (96,364 ) (37,249 ) (32,834 ) Net change in prices and development and production costs from prior year 150,504 (488,160 ) (58,425 ) Extensions, discoveries, and improved recovery, less related costs 147,275 63,341 5,531 Sales of minerals in place (15,042 ) (197 ) (4,433 ) Revisions of previous quantity estimates 74,390 (49,602 ) 12,317 Change in timing and other (82,653 ) 20,419 21,468 Change in future income tax expense (40,636 ) 124,886 — Accretion of discount 34,098 51,256 19,725 Standardized Measure, end of year $ 512,557 $ 197,251 $ 160,600 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, 2014 2015 2016 Oil (per Bbl) (1) $ 95.28 $ 50.12 $ 42.74 Gas (per MMbtu) (2) $ 4.35 $ 2.63 $ 2.50 Oil (per Bbl) (3) $ 87.11 $ 41.25 $ 35.54 Gas (per MMBtu) (4) $ 5.15 $ 2.36 $ 1.41 NGL’s (per Bbl) (5) $ 37.92 $ 10.52 $ 5.17 _____________________ (1) The quoted oil price for the year ended December 31 of each year, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2014, 2015 and 2016. (2) The quoted gas price for the year ended December 31, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2014, 2015 and 2016. (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 24

Organization and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 South Texas. 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. The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, asset retirement obligations, accrued oil and gas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. 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 $296,000 and $228,000 at December 31, 2015 and 2016, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.
Oil and Gas Properties	Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10% , 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. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. For the year ended December 31, 2015, our capitalized cost of oil and gas properties exceeded the present value of our estimated proved reserves by $128.6 million , resulting in the recognition of a proved property impairment of $128.6 million . As of December 31, 2016, our capitalized cost of oil and gas properties did not exceed the present value of our estimated proved reserves. However, we incurred proved property impairments in each of the first three quarters of 2016 in the amount of $67.6 million . The impairment calculations did not consider the impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.
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 unweighted average 12 month first-day-of-month pricing. 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 and three way collars, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could, result in overhedged volumes. All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in its 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, the Company does not account for its derivative instruments as cash flow hedges for financial reporting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts in the Consolidated Statements of Operations.
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 Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. 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, 2014, 2015 and 2016, stock-based compensation was approximately $2.7 million , $3.9 million and $3.2 million , respectively.
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 fair value of a liability for an asset's retirement obligation is 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. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates.
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, 2015 and 2016. During 2014, two purchasers accounted for 62% of oil and gas revenues. During 2015, one purchaser accounted for 54% of oil and gas revenues. During 2016, two purchasers accounted for 71% of our oil and gas revenues.
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 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 with respect 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. Therefore, we have established a valuation allowance of $137.8 million for deferred tax assets at December 31, 2016.
Accounting for Uncertainty in Income Taxes	Accounting for Uncertainty in Income Taxes 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. The Company had no uncertain income tax positions as of December 31, 2016.
Other Comprehensive Income (Loss)	New Accounting Standards and Disclosures I n May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date ("ASU 2015-14"). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. We are currently evaluating the impact, if any, of the standard by comparing historical accounting policies and practices to the new standard and will evaluate guidance from accounting regulatory agencies as it becomes available. The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835) : Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective beginning January 1, 2016 and have been applied using the retrospective approach. These ASUs did not have a material impact on Abraxas's consolidated financial statements and related disclosures. In August 2015, the FASB issued ASU 2015-15, “ Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ”, codifies an SEC staff announcement that entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets. The ASU clarifies that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The ASU is effective immediately for both public business entities and non-public entities. Abraxas has elected to follow this presentation guidance. The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. We have adopted and applied this standard using the retrospective approach. This ASU did not have an impact on our consolidated financial statements and related disclosures. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) : Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment is effective. In February 2016, the FASB issued ASU 2016-02 “ Leases, " which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718) : Improvements to Employee Share-Based Payment Accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's consolidated financial statements. In August 2016, FASB issued amended guidance to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The amendments provide guidance on the following eight specific cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods ending after December 15, 2016, and to annual and interim periods thereafter. Earlier adoption is permitted. The Company has adopted this guidance as of December 31, 2016 and there is no impact on its consolidated financial statements.

Organization and Significant 25

Organization and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2015 2016 (in thousands) Beginning asset retirement obligation $ 9,495 $ 9,679 New wells placed on production and other 307 119 Deletions related to property disposals and plugging costs (793 ) (1,832 ) Accretion expense 565 491 Revisions 105 166 Ending asset retirement obligation $ 9,679 $ 8,623

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-term Debt	The following is a description of the Company’s debt as of December 31, 2015 and 2016, respectively: December 31, December 31, (In thousands) Senior secured credit facility $ 134,000 $ 93,000 Rig loan agreement 2,620 535 Real estate lien note 4,112 3,867 140,732 97,402 Less current maturities (2,330 ) (786 ) $ 138,402 $ 96,616
Maturities of Long-term Debt	Maturities of long-term debt are as follows: Year ending December 31, (In thousands) 2017 $ 786 2018 93,261 2019 273 2020 285 2021 297 Thereafter 2,500 $ 97,402

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2015 2016 Years (In thousands) Oil and gas properties — $ 787,683 $ 794,634 Equipment and other 3-39 18,866 15,227 Drilling rig 15 22,578 23,342 829,127 833,203 Accumulated depreciation, depletion, amortization and impairment (604,289 ) (696,892 ) Net Property and Equipment $ 224,838 $ 136,311

Stock-based Compensation, Opt28

Stock-based Compensation, Option Plans and Warrants (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted Average Assumptions Used in Calculating Fair Value of Options	The Company 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 2014, 2015 and 2016: 2014 2015 2016 Weighted average value per option granted during the period $ 2.44 $ 2.37 $ 0.68 Assumptions: Forfeiture rate (1) 4.2 % 4.5 % 4.2 % Expected dividend yield (2) — % — % — % Volatility (3) 80.7 % 81.1 % 71.1 % Risk free interest rate (4) 2.05 % 1.92 % 1.72 % Expected life (years) (5) 6.6 7.0 7.0 Fair value of options granted (in thousands) $ 2,666 $ 3,792 $ 2,307 ______________________ (1) The estimated future forfeiture rate is based on the Company’s historical forfeiture rate. (2) The dividend yield is based on the fact the Company does not pay any dividends. (3) The volatility is based on the historical volatility of our stock for a period approximating the expected life. (4) The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. (5) The expected life was derived based on a weighting between (a) the Company’s historical exercise and forfeiture activity and (b) the average midpoint between vesting and the contractual term.
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 (000s) Weighted average exercise price Weighted average remaining life Intrinsic value per share 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 Granted 1,601 3.22 Exercised (164 ) 1.03 Forfeited/Expired (514 ) 4.36 Options outstanding December 31, 2015 6,808 $ 2.89 Granted 2,265 1.02 Exercised (83 ) 1.40 Forfeited/Expired (836 ) 2.84 Options outstanding December 31, 2016 8,154 $ 2.39 6.39 1.70 Exercisable at end of year 4,808 4.90 1.93 Other information pertaining to the Company’s stock option activity for the three years ended December 31: 2014 2015 2016 Weighted average grant date fair value of stock options granted (per share) $ 2.44 $ 2.37 $ 0.68 Total fair value of options vested (000’s) $ 1,718 $ 2,035 $ 2,776 Total intrinsic value of options exercised (000’s) $ 932 $ 124 $ 39
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, 2016: Options outstanding Exercisable Number outstanding Weighted average remaining life Weighted average exercise price Number exercisable Weighted average remaining life Weighted average exercise price 0.97 - 1.99 3,462,042 6.7 $ 1.23 1,595,042 3.8 $ 1.52 2.00 - 2.99 1,240,350 5.2 $ 2.35 1,102,063 5.0 $ 2.35 3.00 - 3.99 2,765,633 7.0 $ 3.29 1,438,408 6.3 $ 3.41 4.00 - 4.99 585,750 3.6 $ 4.56 574,750 3.6 $ 4.56 5.00 - 5.99 99,000 7.4 $ 5.39 97,500 7.4 $ 5.38 6.00 - 6.28 1,000 7.5 $ 6.28 500 7.5 $ 6.28 8,153,775 4,808,263
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, 2016: Number of Shares Weighted average grant date fair value 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 Granted — — Vested/Released (127,729 ) 3.38 Forfeited (5,077 ) 2.56 Unvested December 31, 2015 1,643,284 $ 3.44 Granted — — Vested/Released (52,017 ) 2.40 Forfeited (98,802 ) 3.63 Unvested December 31, 2016 1,492,465 $ 3.47

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2014 2015 2016 (In thousands) Deferred tax liabilities: Hedge contracts $ 8,114 $ 9,578 $ — Assets held for sale — — 3,390 Other 4,458 4,042 4,431 Total deferred tax liabilities 12,572 13,620 7,821 Deferred tax assets: U.S. full cost pool 3,352 35,689 48,436 Capital loss carryforward 12,325 7,767 7,361 Depletion carryforward 4,936 5,558 5,216 U.S. net operating loss carryforward 50,941 67,531 80,670 Alternative minimum tax credit 1,104 757 757 Hedge contracts — — 3,135 Total deferred tax assets 72,658 117,302 145,575 Valuation allowance for deferred tax assets (60,086 ) (103,682 ) (137,754 ) Net deferred tax assets 12,572 13,620 7,821 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, 2014 2015 2016 (In thousands) Current: Federal $ (276 ) $ (242 ) $ — State (11 ) (37 ) — $ (287 ) $ (279 ) $ — Deferred: Federal $ — $ — $ — $ — $ — $ —
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, 2014 2015 2016 (In thousands) Tax (expense) benefit at U.S. statutory rates (35%) $ (22,044 ) $ 44,586 $ 33,732 (Increase) decrease in deferred tax asset valuation allowance 15,480 (43,596 ) (34,072 ) Alternative minimum tax — 568 — Rate differential for non US income (39 ) — — State income taxes — — — Accrual of prior year federal taxes (2009 and 2013) 287 37 — Permanent differences (950 ) (1,371 ) (1,133 ) Return to provision estimate revision 4,562 — 1,473 Tax benefit related to the sale of Canadian subsidiary 3,501 — — Increase in asset for partnership distribution — — — Other (510 ) 55 — $ 287 $ 279 $ —

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2014 2015 2016 (In thousands, except per share data) Numerator: Net income (loss) from continuing operations $ 61,951 $ (127,090 ) $ (96,378 ) Net income (loss) from discontinued operations 1,318 (20 ) — $ 63,269 $ (127,110 ) $ (96,378 ) Denominator: Denominator for basic earnings per share – weighted-average common shares outstanding 98,835 104,605 122,132 Effect of dilutive securities: Stock options and restricted shares 2,633 — — Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares 101,468 104,605 122,132 Net income (loss) per common share - basic Continuing operations $ 0.63 $ (1.21 ) $ (0.79 ) Discontinued operations 0.01 — — $ 0.64 $ (1.21 ) $ (0.79 ) Net income (loss) per common share - diluted Continuing operations $ 0.61 $ (1.21 ) $ (0.79 ) Discontinued operations 0.01 — — $ 0.62 $ (1.21 ) $ (0.79 )

Quarterly Results of Operatio31

Quarterly Results of Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2015 and 2016 are as follows: 1 st Quarter 2 nd Quarter 3 rd Quarter 4 th Quarter (In thousands, except per share data) Year Ended December 31, 2015 Net revenue $ 18,661 $ 18,944 $ 16,077 $ 13,348 Operating loss $ (4,535 ) $ (1,531 ) $ (63,438 ) $ (72,301 ) Net loss $ (718 ) $ (6,601 ) $ (52,372 ) $ (67,419 ) Net loss per common share – basic $ (0.01 ) $ (0.06 ) $ (0.50 ) $ (0.64 ) Net loss per common share – diluted $ (0.01 ) $ (0.06 ) $ (0.50 ) $ (0.64 ) Year Ended December 31, 2016 Net revenue $ 9,564 $ 11,008 $ 13,976 $ 22,007 Operating (loss) income $ (40,143 ) $ (31,898 ) $ (4,952 ) $ 3,606 Net loss $ (40,880 ) $ (46,937 ) $ (3,260 ) $ (5,301 ) Net loss per common share – basic $ (0.39 ) $ (0.40 ) $ (0.02 ) $ (0.04 ) Net loss per common share – diluted $ (0.39 ) $ (0.40 ) $ (0.02 ) $ (0.04 )

Hedging Program and Derivativ32

Hedging Program and Derivatives (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016: Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps 2017 2,401 $ 54.53 2018 1,796 $ 47.48 2019 1,200 $ 54.54 Basis Swap 2017 500 $ 0.65 Collar contracts: Gas Contract Periods Daily Volume (Mcf) Floor (Long Put) Ceiling (Short Call) 2017 5,000 $ 3.00 $ 3.90
Collar Contracts	The following table sets forth the summary position of our derivative contracts as of December 31, 2016: Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps 2017 2,401 $ 54.53 2018 1,796 $ 47.48 2019 1,200 $ 54.54 Basis Swap 2017 500 $ 0.65 Collar contracts: Gas Contract Periods Daily Volume (Mcf) Floor (Long Put) Ceiling (Short Call) 2017 5,000 $ 3.00 $ 3.90
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, 2015 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 $ 18,902 Derivatives – current $ — Commodity price derivatives Derivatives – long-term 8,463 Derivatives – long-term — $ 27,365 $ — Fair Value of Derivative Instruments as of December 31, 2016 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 $ 54 Derivatives – current $ 2,382 Commodity price derivatives Derivatives – long-term — Derivatives – long-term 6,630 $ 54 $ 9,012

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2015 and 2016, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2015 Assets: NYMEX Fixed Price Derivative contracts $ — $ 21,731 $ — $ 21,731 NYMEX Collars — — 5,634 5,634 Total Assets $ — $ 21,731 $ 5,634 $ 27,365 Liabilities: NYMEX Fixed Price Derivative contracts $ — $ — $ — $ — Total Liabilities $ — $ — $ — $ — Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2016 Assets: NYMEX Fixed Price Derivative contracts $ — $ 35 $ — $ 35 NYMEX Collars — — 19 19 Total Assets $ — $ 35 $ 19 $ 54 Liabilities: NYMEX Fixed Price Derivative contracts $ — $ 8,759 $ — $ 8,759 NYMEX Collars/basis differential swaps $ — $ — $ 253 $ 253 Total Liabilities $ — $ 8,759 $ 253 $ 9,012
Additional Information for Recurring Fair Value Measurements Using Significant Unobservable Inputs	Additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the year ended December 31, 2016. (In thousands) Unobservable inputs at December 31, 2015 $ 5,634 Changes in market value (2,385 ) Settlements during the period (3,483 ) Unobservable inputs at December 31, 2016 $ (234 )

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations

Subsequent Event (Tables)

Subsequent Event (Tables)	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Schedule of Fixed Price Derivatives	.

Supplemental Oil and Gas Disc36

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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 “Disclosures about Oil and Gas Producing Activities.” Capitalized costs relating to oil and gas producing activities are as follows: Years Ended December 31 2015 2016 (In thousands) Proved oil and gas properties $ 787,683 $ 794,634 Unproved properties — — Total 787,683 794,634 Accumulated depreciation, depletion, amortization and impairment (590,432 ) (680,861 ) Net capitalized costs $ 197,251 $ 113,773
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 2014 2015 2016 (In thousands) Development costs $ 189,322 $ 68,631 $ 18,262 Exploration costs — — 12,529 Property acquisition costs — — — Unproved — — — $ 189,322 $ 68,631 $ 30,791
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, 2014, 2015 and 2016 are as follows: Years Ended December 31, 2014 2015 2016 (In thousands) Revenues $ 133,701 $ 67,002 $ 56,493 Production costs (37,337 ) (29,753 ) (23,659 ) Depreciation, depletion, and amortization (42,945 ) (38,040 ) (22,803 ) Proved property impairment — (128,573 ) (67,626 ) Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) $ 53,419 $ (129,364 ) $ (57,595 ) Depletion rate per barrel of oil equivalent $ 20.39 $ 17.44 $ 10.08
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 unweighted 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. The following is a summary of the changes to the Company’s proved reserves that occurred during 2016: Revisions to prior estimates : An increase of 5,005 MBoe of reserves was attributed to the Company’s Bakken and Three Forks proved undeveloped locations in McKenzie County, ND, due to continuing improvement in its producing well production results. Well results improved as a result of the application of optimized completion methods. Similarly, reserves for the Company’s Bakken and Three Forks producing wells increased by 1,360 MBoe of net producing reserves due to improved performance. On the other hand, projections for the Hedgehog State 16-2H producing well and its two related proved undeveloped locations in the Porcupine Field, Campbell County, WY, decreased by 670 MBoe of net reserves due to the under-performance of the Hedgehog State 16-2H. There was also a reduction in this category of 2,271 MBoe attributable to shortened economic life calculations at the lower commodity pricing. Extensions, discoveries and other additions : The Company added the Caprito 99 302H as a new Wolfcamp producing well in Ward County, TX, accounting for 449 MBoe of net producing reserves. It also added five new proved undeveloped Wolfcamp locations offsetting this new producer accounting for 805 MBoe of net undeveloped reserves. The Company also developed a new Austin Chalk producer in Atascosa County, TX, which accounted for 265 MBoe of net producing reserves. Further, the Company added eight new proved undeveloped Bakken/Three Forks locations on non-operated units in McKenzie County, ND, accounting for 18 MBoe of net undeveloped reserves. These locations were added in response to operator well proposals. Sales: The Company sold all its holdings in the Portilla Field in San Patricio County, TX, and in the Brooks Draw Field in Converse County, WY, during 2016. These sales accounted for 1,232 MBoe of net proved reserves. Production: The Company produced 2,262 MBoe of net reserves during 2016. The following is a summary of the changes to the Company’s proved reserves that occurred during 2015 : Revisions of prior estimates : A total of 48 proved locations accounting for approximately 7.9 net MMBoe of reserves were dropped from the report in 2015 due to lack of economic viability at the lower commodity pricing applied of which 42 were in the undeveloped category. Most significant of these were 38 South Texas Eagle Ford locations representing approximately 7,717 MBoe of net reserves. There was also a reduction of 614 net MBoe attributable to shortened economic life calculations at lower commodity pricing which were partially offset by an increase of 600 net MBoe in the Company’s Bakken/Three Forks undeveloped locations due to better-than-anticipated production. There were also reduction in this category of 1.8 MMBoe of net reserves attributable to shortened economic life calculations at the lower commodity pricing and 1.6 MMBoe of net reserves attributable to lower than anticipated production performance in various wells. Extensions, discoveries and other additions: The Company added 28 new proved undeveloped Bakken locations during 2015 on the Company’s prospect acreage in McKenzie County, North Dakota, accounting for approximately 6.5 MMBoe of net reserves, 20 of which accounting for 4.9 net MMBoe, were for the Three Forks (2 nd Bench) which were proved by local development activity in that reservoir during the year. There were also 8 other cases in the Bakken/Three Forks, accounting for 1.6 net MMBoe, which were added because the Company gained operational control of the Yellowstone Unit resulting in the Company developing the properties in accordance with its normal well spacing pattern. The Company also gained proved undeveloped reserves of approximately 1.3 net MMBOE, due to the change in classification of 21 probable and possible undeveloped Bakken cases into the proved category. This change was warranted by local well development in the specific local areas during 2015. The Company also added 6 new Montoya proved undeveloped locations on the Company’s prospect acreage in Ward County, Texas, accounting for 6.5 MMBOE of net reserves. These locations were added based on the performance of existing Montoya producers on the subject acreage. Sales: During 2015, the Company sold properties accounting for 43 net MBoe of reserves. Production: During 2015, the Company produced 2,181 of net MBoe of reserves Oil NGL Gas Oil Equivalents (MBbl) (MBbl) (MMcf) (MBoe) Proved developed and undeveloped reserves: (in thousands) Balance at December 31, 2013 20,915 2,038 48,109 30,970 Revisions of previous estimates 2,697 1,021 7,383 4,950 Extensions and discoveries 7,780 868 6,893 9,797 Sales of minerals in place (608 ) (12 ) (3,614 ) (1,223 ) Production (1,394 ) (207 ) (2,918 ) (2,088 ) Balance at December 31, 2014 29,390 3,708 55,853 42,406 Revisions of previous estimates (9,485 ) (505 ) (8,002 ) (11,324 ) Extensions and discoveries 5,679 3,591 30,372 14,332 Sales of minerals in place (13 ) — (181 ) (43 ) Production (1,440 ) (238 ) (3,015 ) (2,181 ) Balance at December 31, 2015 24,131 6,556 75,027 43,190 Revisions of previous estimates 1,379 2,300 (1,537 ) 3,424 Extensions and discoveries 1,183 157 1,179 1,537 Sales of minerals in place (1,112 ) (6 ) (680 ) (1,232 ) Production (1,372 ) (363 ) (3,160 ) (2,262 ) Balance at December 31, 2016 24,209 8,644 70,829 44,657 Total Oil NGL Gas Oil Equivalents (MBbl) (MBbl) (MMcf) (MBoe) (In thousands) Proved Developed Reserves: December 31, 2014 10,162 2,006 34,677 17,948 December 31, 2015 10,022 1,956 31,298 17,194 December 31, 2016 7,818 2,568 27,792 15,018 Proved Undeveloped Reserves: December 31, 2014 19,228 1,702 21,176 24,459 December 31, 2015 14,109 4,599 43,729 25,996 December 31, 2016 16,391 6,076 43,037 29,639
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, 2014, 2015 and 2016: Years Ended December 31, 2014 2015 2016 (In thousands) Future cash inflows $ 2,988,464 $ 1,241,334 $ 999,716 Future production costs (921,977 ) (438,784 ) (357,917 ) Future development costs (557,782 ) (338,316 ) (267,836 ) Future income tax expense (373,095 ) — — Future net cash flows 1,135,610 464,234 373,963 Discount (623,053 ) (266,983 ) (213,363 ) Standardized Measure of discounted future net cash relating to proved reserves $ 512,557 $ 197,251 $ 160,600
Analysis of Changes in Standardized Measure	The following is an analysis of the changes in the Standardized Measure: Year Ended December 31, 2014 2015 2016 (In thousands) Standardized Measure, beginning of year $ 340,985 $ 512,557 $ 197,251 Sales and transfers of oil and gas produced, net of production costs (96,364 ) (37,249 ) (32,834 ) Net change in prices and development and production costs from prior year 150,504 (488,160 ) (58,425 ) Extensions, discoveries, and improved recovery, less related costs 147,275 63,341 5,531 Sales of minerals in place (15,042 ) (197 ) (4,433 ) Revisions of previous quantity estimates 74,390 (49,602 ) 12,317 Change in timing and other (82,653 ) 20,419 21,468 Change in future income tax expense (40,636 ) 124,886 — Accretion of discount 34,098 51,256 19,725 Standardized Measure, end of year $ 512,557 $ 197,251 $ 160,600
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, 2014 2015 2016 Oil (per Bbl) (1) $ 95.28 $ 50.12 $ 42.74 Gas (per MMbtu) (2) $ 4.35 $ 2.63 $ 2.50 Oil (per Bbl) (3) $ 87.11 $ 41.25 $ 35.54 Gas (per MMBtu) (4) $ 5.15 $ 2.36 $ 1.41 NGL’s (per Bbl) (5) $ 37.92 $ 10.52 $ 5.17 _____________________ (1) The quoted oil price for the year ended December 31 of each year, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2014, 2015 and 2016. (2) The quoted gas price for the year ended December 31, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2014, 2015 and 2016. (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 37

Organization and Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)region	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Nature of operations [Abstract]
Number of operating regions in domicile country | region	3
Accounts Receivable [Abstract]
Allowance for doubtful accounts	$ 228	$ 296
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%
Proved property impairment	$ 67,626	128,573	$ 0
Share-Based Payments [Abstract]
Stock-based compensation expense	3,194	3,912	2,703
Entity's asset retirement obligation transactions [Roll Forward]
Beginning asset retirement obligation	9,679	9,495
New wells placed on production and other	119	307
Deletions related to property disposals and plugging costs	(1,832)	(793)
Accretion expense	(491)	(565)	(559)
Revisions	166	105
Ending asset retirement obligation	$ 8,623	$ 9,679	$ 9,495
Revenue Recognition and Major Purchasers [Abstract]
Entity wide revenue, major customers (in hundredths)	71.00%	54.00%	62.00%
Entity wide revenue, number of major purchasers of oil and gas	2	1	2
Income Taxes [Abstract]
Valuation allowance for deferred tax assets	$ 137,754	$ 103,682	$ 60,086

Divestiture of Non-Core Prope38

Divestiture of Non-Core Properties (Details) - USD ($) $ in Thousands	12 Months Ended			54 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Divestiture of Non Core Properties [Abstract]
Net proceeds from divestiture of non-core properties				$ 169,900
Gain (Loss) on Sale of Property	$ 374	$ 0	$ 0

Long-Term Debt (Details)

Long-Term Debt (Details)	Jul. 20, 2013USD ($)	Dec. 31, 2016USD ($)borrowing_base	Dec. 31, 2015USD ($)	Feb. 14, 2012USD ($)	Sep. 19, 2011hp
Long-term debt [Abstract]
Long-term debt		$ 97,402,000	$ 140,732,000
Less current maturities		(786,000)	(2,330,000)
Long-term debt – less current maturities		96,616,000	138,402,000
Maturities of long-term debt [Abstract]
2,015		786,000
2,016		93,261,000
2,017		273,000
2,018		285,000
2,019		297,000
Thereafter		2,500,000
Credit Facility [Abstract]
Maximum borrowing capacity		300,000,000
Current borrowing base		$ 115,000,000
Number of reserve reports prepared by independent petroleum engineers | borrowing_base		1
Number of reserve report prepared internally | borrowing_base		1
Number of borrowing base redetermination | borrowing_base		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		2.50
Financial covenants, total debt To EBITDAX ratio		4
Interest coverage ratio		10.49
Total debt to EBITDAX ratio		2.32
Current ratio		1.64
Senior Secured Credit Facility [Member]
Long-term debt [Abstract]
Long-term debt		$ 93,000,000	134,000,000
Maturities of long-term debt [Abstract]
Maturity date of debt instrument		Jun. 30, 2018
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)		3.27%
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		$ 535,000	2,620,000
Rig Loan Agreement [Abstract]
Power of diesel electric drilling rig (in horsepower) | hp					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		$ 3,867,000	$ 4,112,000
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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property and equipment	$ 833,203	$ 829,127
Accumulated depreciation, depletion, amortization and impairment	(696,892)	(604,289)
Net Property and Equipment	136,311	224,838
Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property and equipment	794,634	787,683
Equipment and Other [Member]
Property, Plant and Equipment [Line Items]
Property and equipment	$ 15,227	18,866
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	$ 23,342	$ 22,578

Stock-based Compensation, Opt41

Stock-based Compensation, Option Plans and Warrants (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Apr. 30, 2012	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		$ 3,194	$ 3,912	$ 2,703
Director Stock Awards [Abstract]
Shares reserved for issuance (in shares)		8,966,402
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding, Number (in shares)		8,153,775
Exercisable, Number (in shares)		4,808,263
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Forfeiture Rate		4.00%	5.00%	4.00%
Stock-based compensation expense		$ 1,960	$ 2,376	$ 1,820
Weighted average assumptions used in fair value of the options [Abstract]
Weighted average value per option granted during the period (in dollars per share)		$ 0.68	$ 2.37	$ 2.44
Assumptions [Abstract]
Expected dividend yield (in hundredths)		0.00%	0.00%	0.00%
Volatility (in hundredths)		71.10%	81.10%	80.70%
Risk free interest rate (in hundredths)		1.72%	1.92%	2.05%
Expected life (years)		7 years	7 years	6 years 7 months 6 days
Fair value of options granted		$ 2,307	$ 3,792	$ 2,666
Options expiration period		10 years
Options [Roll Forward]
Options outstanding, beginning balance (in shares)		6,808,000	5,885,000	5,400,000
Granted (in shares)		2,265,000	1,601,000	1,091,000
Exercised (in shares)		(83,000)	(164,000)	(410,000)
Forfeited/Expired (in shares)		(836,000)	(514,000)	(196,000)
Options outstanding, ending balance (in shares)		8,154,000	6,808,000	5,885,000
Exercisable at end of year (in shares)		4,808,000
Weighted average exercise price [Roll Forward]
Options outstanding, beginning balance (in dollars per share)		$ 2.89	$ 2.88	$ 2.77
Granted (in dollars per share)		1.02	3.22	3.38
Exercised (in dollars per share)		1.40	1.03	2.71
Forfeited/Expired (in dollars per share)		2.84	4.36	3.08
Options outstanding, ending balance (in dollars per share)		$ 2.39	2.89	2.88
Options outstanding weighted average exercise price of options exercisable
Weighted average remaining life [Abstract]
Options outstanding ending balance		6 years 4 months 21 days
Exercisable at end of year		4 years 10 months 24 days
Fair value per share [Abstract]
Options outstanding, ending balance (in dollars per share)			1.70
Exercisable at end of year, Fair value (in dollars per share)			1.93
Other information pertaining to stock options activity [Abstract]
Weighted average grant date fair value of stock options granted (in dollars per share)		$ 0.68	$ 2.37	$ 2.44
Total fair value of options vested		$ 2,776	$ 2,035	$ 1,718
Total intrinsic value of options exercised		39	124	932
Compensation cost related to non-vested awards not yet recognized		2,944
Restricted Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		1,234	$ 1,536	$ 883
Restricted Stock Awards [Abstract]
Compensation cost not yet recognized		$ 1,903
Number of Shares [Roll Forward]
Unvested, Beginning balance (in shares)		1,643,284	1,776,090	355,240
Granted (in shares)		0	0	1,582,000
Vested/Released (in shares)		(52,017)	(127,729)	(121,622)
Forfeited (in shares)		(98,802)	(5,077)	(39,528)
Unvested, Ending balance (in shares)		1,492,465	1,643,284	1,776,090
Weighted average grant date fair value [Roll Forward]
Unvested, beginning balance (in dollars per share)		$ 3.44	$ 3.43	$ 3.24
Granted (in dollars per share)		0	0	3.49
Vested/Released (in dollars per share)		2.40	3.38	3.64
Forfeited (in dollars per share)		3.63	2.56	3.44
Unvested, Ending balance (in dollars per share)		$ 3.47	$ 3.44	$ 3.43
2005 Directors Plan [Member]
Director Stock Awards [Abstract]
Shares reserved for issuance (in shares)		1,900,000
Number of shares to be granted for participation in board and committee meetings as per agreement (in shares)		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
0.97 - 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)		3,462,042
Options outstanding, Weighted average remaining life		6 years 8 months 12 days
Options outstanding, Weighted average exercise price (in dollars per share)		$ 1.23
Exercisable, Number (in shares)		1,595,042
Exercisable, Weighted average remaining life		3 years 9 months 18 days
Exercisable, Weighted average exercise price (in dollars per share)		$ 1.52
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)		1,240,350
Options outstanding, Weighted average remaining life		5 years 2 months 12 days
Options outstanding, Weighted average exercise price (in dollars per share)		$ 2.35
Exercisable, Number (in shares)		1,102,063
Exercisable, Weighted average remaining life		5 years
Exercisable, Weighted average exercise price (in dollars per share)		$ 2.35
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)		2,765,633
Options outstanding, Weighted average remaining life		7 years
Options outstanding, Weighted average exercise price (in dollars per share)		$ 3.29
Exercisable, Number (in shares)		1,438,408
Exercisable, Weighted average remaining life		6 years 3 months 18 days
Exercisable, Weighted average exercise price (in dollars per share)		$ 3.41
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)		585,750
Options outstanding, Weighted average remaining life		3 years 7 months 6 days
Options outstanding, Weighted average exercise price (in dollars per share)		$ 4.56
Exercisable, Number (in shares)		574,750
Exercisable, Weighted average remaining life		3 years 7 months 6 days
Exercisable, Weighted average exercise price (in dollars per share)		$ 4.56
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)		99,000
Options outstanding, Weighted average remaining life		7 years 4 months 24 days
Options outstanding, Weighted average exercise price (in dollars per share)		$ 5.39
Exercisable, Number (in shares)		97,500
Exercisable, Weighted average remaining life		7 years 4 months 24 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)		1,000
Options outstanding, Weighted average remaining life		7 years 6 months
Options outstanding, Weighted average exercise price (in dollars per share)		$ 6.28
Exercisable, Number (in shares)		500
Exercisable, Weighted average remaining life		7 years 6 months
Exercisable, Weighted average exercise price (in dollars per share)		$ 6.28

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred tax liabilities [Abstract]
Hedge contracts	$ 0	$ 9,578	$ 8,114
Assets held for sale	3,390	0	0
Deferred Tax Liabilities, Other	4,431	4,042	4,458
Total deferred tax liabilities	7,821	13,620	12,572
Deferred tax assets [Abstract]
U.S. full cost pool	48,436	35,689	3,352
Deferred Tax Assets, Capital Loss Carryforwards	7,361	7,767	12,325
Depletion carryforward	5,216	5,558	4,936
U.S. net operating loss carryforward	80,670	67,531	50,941
Alternative minimum tax credit	757	757	1,104
Hedge contracts	3,135	0	0
Total deferred tax assets	145,575	117,302	72,658
Valuation allowance for deferred tax assets	(137,754)	(103,682)	(60,086)
Net deferred tax assets	7,821	13,620	12,572
Net deferred tax	0	0	0
Current [Abstract]
Federal	0	(242)	(276)
State	0	(37)	(11)
Current provision (benefit) for income taxes	0	(279)	(287)
Deferred [Abstract]
Federal	0	0	0
Deferred provision (benefit) for income taxes	0	0	0
Reconciliation of income tax computed at U.S federal statutory tax rates [Abstract]
Tax (expense) benefit at U.S. statutory rates (35%)	33,732	44,586	(22,044)
(Increase) decrease in deferred tax asset valuation allowance	(34,072)	(43,596)	15,480
Alternative minimum tax	0	568	0
Rate differential for non US income	0	0	(39)
State income taxes	0	0	0
Accrual of prior year federal taxes (2009)	0	37	287
Permanent differences	(1,133)	(1,371)	(950)
Return to provision estimate revision	1,473	0	4,562
Tax benefit related to the sale of Canadian subsidiary	0	0	3,501
Increase in asset for partnership distributions	0	0	0
Other	0	55	(510)
Income tax (expense) benefit	$ 0	$ 279	$ 287
U.S statutory rate (in hundredths)	35.00%
Reduction in deferred tax assets	$ 28,300
U.S. Tax [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 230,500
Expiration dates of operating loss carryforwards	Dec. 31, 2036

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Office Space in Dickinson, North Dakota [Member]
Operating Leased Assets [Line Items]
Rent expense	$ 27,840	$ 27,165	$ 26,265
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	$ 15,766	$ 15,601	$ 14,554

Earnings per Share (Details)

Earnings per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Numerator [Abstract]
Net income (loss) from continuing operations									$ (96,378)	$ (127,090)	$ 61,951
Net income (loss) from discontinued operations									0	(20)	1,318
Net income (loss)	$ (5,301)	$ (67,419)	$ (3,260)	$ (46,937)	$ (40,880)	$ (52,372)	$ (6,601)	$ (718)	$ (96,378)	$ (127,110)	$ 63,269
Denominator [Abstract]
Denominator for basic earnings per share – weighted-average common shares outstanding (shares)									122,132,000	104,605,000	98,835,000
Effect of dilutive securities [Abstract]
Stock options, restricted shares and warrants (in shares)									0	0	2,633,000
Dilutive potential common shares [Abstract]
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and warrants (in shares)									122,132,000	104,605,000	101,468,000
Earnings Per Share, Basic [Abstract]
Continuing operations (in dollars per share)									$ (0.79)	$ (1.21)	$ 0.63
Discontinued operations (in dollars per share)									0	0	0.01
Total (in dollars per share)	$ (0.04)	$ (0.64)	$ (0.02)	$ (0.40)	$ (0.39)	$ (0.50)	$ (0.06)	$ (0.01)	(0.79)	(1.21)	0.64
Earnings Per Share, Diluted [Abstract]
Continuing operations (in dollars per share)									(0.79)	(1.21)	0.61
Discontinued operations (in dollars per share)									0	0	0.01
Total (in dollars per share)	$ (0.04)	$ (0.64)	$ (0.02)	$ (0.40)	$ (0.39)	$ (0.50)	$ (0.06)	$ (0.01)	$ (0.79)	$ (1.21)	$ 0.62
Stock options excluded from the calculation of diluted income (loss) per share (in shares)									624	0	624

Quarterly Results of Operatio45

Quarterly Results of Operations (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Net revenue	$ 22,007	$ 13,348	$ 13,976	$ 11,008	$ 9,564	$ 16,077	$ 18,944	$ 18,661	$ 56,555	$ 67,030	$ 133,776
Operating income (loss)	3,606	(72,301)	(4,952)	(31,898)	(40,143)	(63,438)	(1,531)	(4,535)	(73,387)	(141,805)	39,922
Net income (loss)	$ (5,301)	$ (67,419)	$ (3,260)	$ (46,937)	$ (40,880)	$ (52,372)	$ (6,601)	$ (718)	$ (96,378)	$ (127,110)	$ 63,269
Net income (loss) per common share - basic (in dollars per share)	$ (0.04)	$ (0.64)	$ (0.02)	$ (0.40)	$ (0.39)	$ (0.50)	$ (0.06)	$ (0.01)	$ (0.79)	$ (1.21)	$ 0.64
Net income (loss) - per common share - diluted (in dollars per share)	$ (0.04)	$ (0.64)	$ (0.02)	$ (0.40)	$ (0.39)	$ (0.50)	$ (0.06)	$ (0.01)	$ (0.79)	$ (1.21)	$ 0.62

Benefit Plans (Details)

Benefit Plans (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Contribution to 401(k) plan	$ 256,309	$ 347,632	$ 313,899
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	$ 18,000	18,000	17,500
Employee contribution limit for employees of 50 years of age or older	$ 24,000	$ 24,000	$ 23,000

Hedging Program and Derivativ47

Hedging Program and Derivatives (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / bblbbl	Dec. 31, 2015USD ($)
Impact of derivative contracts on balance sheet [Abstract]
Derivative asset - current	$ 54	$ 18,902
Derivative asset - long-term	0	8,463
Derivative Assets	54	27,365
Derivative liability - current	2,382	0
Derivative liability - long-term	6,630	0
Derivative Liabilities	$ 9,012	0
Three-way Collar [Member] | Not Designated as Hedging Instrument [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Daily Volume (in Bbl) | bbl	5,000
Derivative Asset - Current [Member] | Commodity Price Derivatives [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative asset - current	$ 54	18,902
Derivative Asset - Long-Term [Member] | Commodity Price Derivatives [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative asset - long-term	0	8,463
Derivative Liability - Current [Member] | Commodity Price Derivatives [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative liability - current	2,382	0
Derivative Liability - Long-Term [Member] | Commodity Price Derivatives [Member]
Impact of derivative contracts on balance sheet [Abstract]
Derivative liability - long-term	$ 6,630	$ 0
Long Put [Member] | Three-way Collar [Member] | Not Designated as Hedging Instrument [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Derivative, floor | $ / bbl	3
Short Call [Member] | Three-way Collar [Member] | Not Designated as Hedging Instrument [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Derivative, ceiling | $ / bbl	3.90

Financial Instruments (Details)

Financial Instruments (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	$ 54,000	$ 27,365,000
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	9,012,000	0
Derivative Assets (Liabilities) - net [Roll Forward]
Unobservable inputs at December 31, 2015	5,634
Changes in market value	(2,385)
Settlements during the period	(3,483)
Unobservable inputs at December 31, 2016	(234)
Recurring Basis [Member]
Assets [Abstract]
Total Assets	54,000	27,365,000
Liabilities [Abstract]
Total Liabilities	9,012,000	0
Recurring Basis [Member] | Fixed Price Derivative Contracts [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	35,000	21,731,000
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	8,759,000	0
Recurring Basis [Member] | Collars [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	19,000
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets [Abstract]
Total Assets	0	0
Liabilities [Abstract]
Total Liabilities	0	0
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Fixed Price Derivative Contracts [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	0	0
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	0	0
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Collars [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	0
Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets [Abstract]
Total Assets	35,000	21,731,000
Liabilities [Abstract]
Total Liabilities	8,759,000	0
Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member] | Fixed Price Derivative Contracts [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	35,000	21,731,000
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	8,759,000	0
Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member] | Collars [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	0
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets [Abstract]
Total Assets	19,000	5,634,000
Liabilities [Abstract]
Total Liabilities	253,000	0
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Fixed Price Derivative Contracts [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	0	0
Liabilities [Abstract]
NYMEX Fixed Price Derivative contracts	0	$ 0
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Collars [Member]
Assets [Abstract]
NYMEX Fixed Price Derivative contracts	$ 19,000

Discontinued Operations (Detail

Discontinued Operations (Details) - Canadian Abraxas Petroleum, UCL - USD ($) $ in Millions	10 Months Ended	12 Months Ended
	Oct. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale		$ 1.9
Revenue			$ 2
Net loss	$ (0.6)

Subsequent Event (Details)

Subsequent Event (Details) - USD ($) $ in Thousands, shares in Millions	1 Months Ended	3 Months Ended	4 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Subsequent Event [Line Items]
Proceeds from the sale of non-oil and gas properties		$ 1,100		$ 4,022	$ 0	$ 0
Monetization of derivative contracts				$ 14,370	$ 4,610	$ 152
Subsequent Event [Member]
Subsequent Event [Line Items]
Proceeds from the sale of non-oil and gas properties			$ 10,600
Common Stock [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Stock issuance (in shares)	28.8
Proceeds from sale of equity	$ 65,300

Supplemental Oil and Gas Disc51

Supplemental Oil and Gas Disclosures (Unaudited) (Details) bbl in Thousands, Mcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)Boelocation$ / bblbblMcf	Dec. 31, 2015USD ($)Boe$ / bblbblMcf	Dec. 31, 2014USD ($)Boe$ / bblbblMcf
Capitalized costs relating to oil and gas producing activities [Abstract]
Proved oil and gas properties	$ 794,634	$ 787,683
Unproved properties	0	0
Total	794,634	787,683
Accumulated depreciation, depletion, amortization and impairment	(680,861)	(590,432)
Net capitalized costs	113,773	197,251
Cost incurred in oil and gas property acquisition and development activities [Abstract]
Development costs	18,262	68,631	$ 189,322
Exploration costs	12,529	0	0
Property acquisition costs	0	0	0
Unproved	0	0	0
Total	30,791	68,631	189,322
Results of operations for oil and gas producing activities [Abstract]
Revenues	56,493	67,002	133,701
Production costs	(23,659)	(29,753)	(37,337)
Depreciation, depletion, and amortization	(22,803)	(38,040)	(42,945)
Proved property impairment	(67,626)	(128,573)	0
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$ (57,595)	$ (129,364)	$ 53,419
Depletion per barrel of oil equivalent | $ / bbl	10.08	17.44	20.39
Oil [Member]
Proved developed and undeveloped reserves [Abstract]
Balance | bbl	24,131	29,390	20,915
Revisions of previous estimates | bbl	1,379	(9,485)	2,697
Extensions and discoveries | bbl	1,183	5,679	7,780
Sales of minerals in place | bbl	(1,112)	(13)	(608)
Production | bbl	(1,372)	(1,440)	(1,394)
Balance | bbl	24,209	24,131	29,390
Proved Developed Reserves [Abstract]
Proved Developed Reserves | bbl	7,818	10,022	10,162
Proved Undeveloped Reserves [Abstract]
Proved Undeveloped Reserves | bbl	16,391	14,109	19,228
NGL [Member]
Proved developed and undeveloped reserves [Abstract]
Balance | bbl	6,556	3,708	2,038
Revisions of previous estimates | bbl	2,300	(505)	1,021
Extensions and discoveries | bbl	157	3,591	868
Sales of minerals in place | bbl	(6)	0	(12)
Production | bbl	(363)	(238)	(207)
Balance | bbl	8,644	6,556	3,708
Proved Developed Reserves [Abstract]
Proved Developed Reserves | Mcf	3	2	2
Proved Undeveloped Reserves [Abstract]
Proved Undeveloped Reserves | Mcf	6	5	2
Natural Gas [Member]
Proved developed and undeveloped reserves [Abstract]
Balance | Mcf	75,027	55,853	48,109
Revisions of previous estimates | Mcf	(1,537)	(8,002)	7,383
Extensions and discoveries | Mcf	1,179	30,372	6,893
Sales of minerals in place | Mcf	(680)	(181)	(3,614)
Production | Mcf	(3,160)	(3,015)	(2,918)
Balance | Mcf	70,829	75,027	55,853
Proved Developed Reserves [Abstract]
Proved Developed Reserves | Mcf	27,792	31,298	34,677
Proved Undeveloped Reserves [Abstract]
Proved Undeveloped Reserves | Mcf	43,037	43,729	21,176
Oil Equivalents [Member]
Proved developed and undeveloped reserves [Abstract]
Balance | Boe	43,190,000	42,406,000	30,970,000
Revisions of previous estimates | Boe	5,005,000
Extensions and discoveries | Boe	1,537,000	14,332,000	9,797,000
Sales of minerals in place | Boe	(1,232,000)	(43,000)	(1,223,000)
Production | Boe	(2,262,000)	(2,181,000)	(2,088,000)
Balance | Boe	44,657,000	43,190,000	42,406,000
Proved Developed Reserves [Abstract]
Proved Developed Reserves | Boe	15,018,000	17,194,000	17,948,000
Proved Undeveloped Reserves [Abstract]
Proved Undeveloped Reserves | Boe	29,639,000	25,996,000	24,459,000
NORTH DAKOTA | Oil Equivalents [Member]
Proved Undeveloped Reserves [Abstract]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | Boe	0
Gas and Oil Area, Undeveloped, Additional Down-Spaced Locations | location	8
Proved Undeveloped Reserves (Energy) | Boe	6,500,000,000
North Dakota - Bakken [Member] | Oil Equivalents [Member]
Proved Undeveloped Reserves [Abstract]
Gas and Oil Area, Undeveloped, Additional Locations | location	28
Proved Undeveloped Reserves (Energy) | Boe	21
North Dakota - Three Forks [Member] | Oil Equivalents [Member]
Proved Undeveloped Reserves [Abstract]
Gas and Oil Area, Undeveloped, Additional Locations | location	20
Proved Undeveloped Reserves (Energy) | Boe	4,900,000,000
Texas - Montoya [Member] | Oil Equivalents [Member]
Proved Undeveloped Reserves [Abstract]
Gas and Oil Area, Undeveloped, Additional Locations | location	6
Proved Undeveloped Reserves (Energy) | Boe	6.5

Supplemental Oil and Gas Disc52

Supplemental Oil and Gas Disclosures (Unaudited), Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)Boelocation$ / bbl$ / MMBTU	Dec. 31, 2015USD ($)Boelocation$ / bbl$ / MMBTU	Dec. 31, 2014USD ($)Boe$ / bbl$ / MMBTU	Dec. 31, 2016USD ($)Boelocation	Dec. 31, 2015USD ($)Boe	Dec. 31, 2014USD ($)Boe
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		38 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 | $					$ 999,716	$ 1,241,334	$ 2,988,464
Future production costs | $					(357,917)	(438,784)	(921,977)
Future development costs | $					(267,836)	(338,316)	(557,782)
Future income tax expense | $					0	0	(373,095)
Future net cash flows | $					373,963	464,234	1,135,610
Discount | $					(213,363)	(266,983)	(623,053)
Standardized Measure of discounted future net cash relating to proved reserves | $		$ 197,251	$ 512,557	$ 340,985	$ 160,600	$ 197,251	$ 512,557
Analysis of the changes in Standardized Measure [Roll Forward]
Standardized Measure, beginning of year | $		197,251	512,557	340,985
Sales and transfers of oil and gas produced, net of production costs | $		32,834	37,249	96,364
Net change in prices and development and production costs from prior year | $		(58,425)	(488,160)	150,504
Extensions, discoveries, and improved recovery, less related costs | $		5,531	63,341	147,275
Sales of minerals in place | $		(4,433)	(197)	(15,042)
Revisions of previous quantity estimates | $		12,317	(49,602)	74,390
Change in timing and other | $		21,468	20,419	(82,653)
Change in future income tax expense | $		0	124,886	(40,636)
Accretion of discount | $		19,725	51,256	34,098
Standardized Measure, end of year | $		$ 160,600	$ 197,251	$ 512,557
Oil and gas prices considered in standardized measure of discounted future net cash flows [Abstract]
Oil (in dollars per Bbl) | $ / bbl	[1]	42.74	50.12	95.28
Gas (in dollars per MMbtu) | $ / MMBTU	[2]	2.50	2.63	4.35
Oil (in dollars per Bbl) | $ / bbl	[3]	35.54	41.25	87.11
Gas (in dollars per MMBtu) | $ / MMBTU	[4]	1.41	2.36	5.15
NGL's (in dollars per Bbl) | $ / bbl	[5]	5.17	10.52	37.92
Porcupine Field, Campbell County, WY [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved undeveloped locations | location					2
Oil Equivalents [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place, Energy		1,232,000	43,000	1,223,000
Proved Developed and Undeveloped Reserves, Production, Energy		2,262,000	2,181,000	2,088,000
Proved Developed and Undeveloped Reserves, Production, Net, Energy		2,262,000,000
Proved Developed and Undeveloped Locations Dropped Due to Lack of Economic Viability | location			48
Proved Undeveloped Reserve (Energy)					29,639,000	25,996,000	24,459,000
Proved Developed and Undeveloped Reserves (Energy), Revisions of Previous Estimates Due to Lack of Economic Viability			7,900,000
Proved Developed and Undeveloped Reserves, Production, Energy		3,424,000	(11,324,000)	4,950,000
Proved undeveloped locations dropped due to lack of economic viability | location			42
Proved developed and undeveloped reserves (energy), revisions of previous estimates due to shortened economic life calculations			614,000
Extensions and discoveries		1,537,000	14,332,000	9,797,000
Proved Developed Reserves					15,018,000	17,194,000	17,948,000
Oil Equivalents [Member] | Texas - Montoya [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Undeveloped Reserves (Energy)					6.5
Gas and Oil Area, Undeveloped, Additional Locations | location		6
Oil Equivalents [Member] | North Dakota - Three Forks [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Undeveloped Reserves (Energy)					4,900,000,000
Gas and Oil Area, Undeveloped, Additional Locations | location		20
Oil Equivalents [Member] | Porcupine Field, Campbell County, WY [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Production, Energy		670,000
Proved developed and undeveloped reserves (energy), revisions of previous estimates due to shortened economic life calculations		2,271,000
Oil Equivalents [Member] | Ward County, TX [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Undeveloped Locations Added | location		5
Proved Undeveloped Reserve (Energy)					805,000
Proved Developed Reserves					449,000
Oil Equivalents [Member] | Atascosa County, TX [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed Reserves					265,000,000
Oil Equivalents [Member] | McKenzie County, ND [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Undeveloped Reserve (Energy)					18,000
Oil Equivalents [Member] | San Patricio County, TX and Converse County, WY [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place, Energy		1,232,000,000
Oil Equivalents [Member] | South Texas Eagle Ford Locations [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves (Energy), Revisions of Previous Estimates Due to Lack of Economic Viability			7,717,000
Proved undeveloped locations dropped due to lack of economic viability | location			38
Oil Equivalents [Member] | North Dakota - Bakken and Three Forks [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Undeveloped Reserves (Energy)					1,600,000,000
Proved developed and undeveloped reserves (energy), revisions of previous estimates due to shortened economic life calculations			1,800,000,000
Proved Developed and Undeveloped Reserves (Energy), Revisions of Previous Estimates, Increase Due To Better Than Anticipated Production			600,000
Proved developed and undeveloped reserves (energy), revisions of previous estimates due to lower than anticipated performance			1,600,000,000
Oil Equivalents [Member] | North Dakota - Bakken and Three Forks [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Production, Energy		1,360,000
[1]	The quoted oil price for the year ended December 31 of each year, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2014, 2015 and 2016.
[2]	The quoted gas price for the year ended December 31, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2014, 2015 and 2016.
[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.