Approach Resources (AREXQ) 10-K 10 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 06, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Trading Symbol	AREX
Entity Registrant Name	Approach Resources Inc
Entity Central Index Key	1,405,073
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		80,903,376
Entity Public Float			$ 80.3

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 21	$ 600
Accounts receivable:
Joint interest owners	92	142
Oil, NGLs and gas sales	9,547	11,747
Unrealized gain on commodity derivatives		6,737
Prepaid expenses and other current assets	2,834	1,212
Total current assets	12,494	20,438
PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting	1,869,774	1,853,781
Furniture, fixtures and equipment	5,644	5,628
Total oil and gas properties and equipment	1,875,418	1,859,409
Less accumulated depletion, depreciation and amortization	(783,357)	(704,863)
Net oil and gas properties and equipment	1,092,061	1,154,546
Total assets	1,104,555	1,174,984
CURRENT LIABILITIES:
Accounts payable	9,482	10,799
Oil, NGLs and gas sales payable	4,190	4,245
Unrealized loss on commodity derivatives	4,880
Accrued liabilities	7,817	13,464
Total current liabilities	26,369	28,508
NON-CURRENT LIABILITIES:
Senior secured credit facility, net	271,696	270,748
Senior notes, net	226,653	225,839
Deferred income taxes	5,615	31,779
Asset retirement obligations	10,607	10,143
Other non-current liabilities	663
Total liabilities	541,603	567,017
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS’ EQUITY :
Preferred stock, $0.01 par value, 10,000,000 shares authorized none outstanding
Common stock, $0.01 par value, 90,000,000 shares authorized, 41,764,770 and 40,788,705 issued and outstanding, respectively	418	408
Additional paid-in capital	586,095	580,623
Accumulated (deficit) earnings	(23,561)	26,936
Total stockholders’ equity	562,952	607,967
Total liabilities and stockholders’ equity	$ 1,104,555	$ 1,174,984

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	90,000,000	90,000,000
Common stock, issued	41,764,770	40,788,705
Common stock, outstanding	41,764,770	40,788,705

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES:
Oil, NGLs and gas sales		$ 90,302,000	$ 131,336,000	$ 258,529,000
EXPENSES:
Lease operating		19,250,000	28,972,000	32,701,000
Production and ad valorem taxes		8,217,000	11,085,000	15,934,000
Exploration		3,923,000	4,439,000	3,831,000
General and administrative	[1]	24,734,000	28,341,000	32,104,000
Termination costs			1,436,000
Impairment of oil and gas properties		0	220,197,000	0
Depletion, depreciation and amortization		79,044,000	109,319,000	106,802,000
Total expenses		135,168,000	403,789,000	191,372,000
OPERATING (LOSS) INCOME		(44,866,000)	(272,453,000)	67,157,000
OTHER:
Interest expense, net		(27,259,000)	(25,066,000)	(21,651,000)
Gain on debt extinguishment			10,563,000
Write-off of debt issuance costs		(563,000)
Equity in losses of investee				(181,000)
Realized gain on commodity derivatives		6,132,000	52,489,000	2,359,000
Unrealized (loss) gain on commodity derivatives		(11,616,000)	(33,214,000)	42,113,000
Other income		1,511,000	172,000	67,000
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION		(76,661,000)	(267,509,000)	89,864,000
INCOME TAX (BENEFIT) PROVISION:
Current			(265,000)	(25,000)
Deferred		(24,418,000)	(93,140,000)	33,717,000
NET (LOSS) INCOME		$ (52,243,000)	$ (174,104,000)	$ 56,172,000
(LOSS) EARNINGS PER SHARE:
Basic		$ (1.26)	$ (4.30)	$ 1.43
Diluted		$ (1.26)	$ (4.30)	$ 1.42
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		41,488,206	40,464,283	39,407,733
Diluted		41,488,206	40,464,283	39,419,865
[1]	Includes non-cash share-based compensation expense as follows:

Consolidated Statements of Ope5

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Includes non-cash share-based compensation expense	$ 6,279	$ 7,954	$ 8,247

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated (Deficit) Earnings [Member]
Beginning balance, value at Dec. 31, 2013	$ 710,495	$ 390	$ 565,237	$ 144,868
Beginning balance, shares at Dec. 31, 2013		39,047,699
Issuance of common shares to directors for compensation, value	749	$ 1	748
Issuance of common shares to directors for compensation, shares		40,898
Restricted stock issuance, net of cancellations, value		$ 8	(8)
Restricted stock issuance, net of cancellations, shares		782,708
Share-based compensation expense	7,498		7,498
Surrender of restricted shares for payment of income taxes, value	(587)		(587)
Surrender of restricted shares for payment of income taxes, shares		(57,106)
Net (loss) income	56,172			56,172
Ending balance, value at Dec. 31, 2014	774,327	$ 399	572,888	201,040
Ending balance, shares at Dec. 31, 2014		39,814,199
Issuance of common shares to directors for compensation, value	735	$ 1	734
Issuance of common shares to directors for compensation, shares		134,783
Restricted stock issuance, net of cancellations, value		$ 8	(8)
Restricted stock issuance, net of cancellations, shares		897,285
Share-based compensation expense	7,219		7,219
Surrender of restricted shares for payment of income taxes, value	(210)		(210)
Surrender of restricted shares for payment of income taxes, shares		(57,562)
Net (loss) income	(174,104)			(174,104)
Ending balance, value at Dec. 31, 2015	607,967	$ 408	580,623	26,936
Ending balance, shares at Dec. 31, 2015		40,788,705
Cumulative effect of change in accounting principal	1,746			1,746
Issuance of common shares to directors for compensation, value	214	$ 2	212
Issuance of common shares to directors for compensation, shares		196,287
Restricted stock issuance, net of cancellations, value		$ 10	(10)
Restricted stock issuance, net of cancellations, shares		1,013,982
Share-based compensation expense	6,065		6,065
Surrender of restricted shares for payment of income taxes, value	(797)	$ (2)	(795)
Surrender of restricted shares for payment of income taxes, shares		(234,204)
Net (loss) income	(52,243)			(52,243)
Ending balance, value at Dec. 31, 2016	$ 562,952	$ 418	$ 586,095	$ (23,561)
Ending balance, shares at Dec. 31, 2016		41,764,770

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES:
Net (loss) income	$ (52,243,000)	$ (174,104,000)	$ 56,172,000
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization	79,044,000	109,319,000	106,802,000
Impairment of oil and gas properties	0	220,197,000	0
Amortization of debt issuance costs	1,396,000	1,561,000	1,546,000
Gain on debt extinguishment		(10,563,000)
Write-off of debt issuance costs	563,000
Unrealized loss (gain) on commodity derivatives	11,616,000	33,214,000	(42,113,000)
Exploration expense	3,753,000	1,836,000	3,831,000
Share-based compensation expense	6,279,000	7,954,000	8,247,000
Deferred income tax (benefit) expense	(24,418,000)	(93,140,000)	33,717,000
Equity in losses of investee			181,000
Other non-cash items	(92,000)	(172,000)	(179,000)
Changes in operating assets and liabilities:
Accounts receivable	2,250,000	7,878,000	3,262,000
Prepaid expenses and other current assets	534,000	(325,000)	(179,000)
Accounts payable	358,000	964,000	(2,262,000)
Oil, NGLs and gas sales payable	(55,000)	(4,291,000)	2,435,000
Accrued liabilities	(2,904,000)	2,388,000	144,000
Cash provided by operating activities	26,081,000	102,716,000	171,604,000
INVESTING ACTIVITIES:
Additions to oil and gas properties	(19,788,000)	(151,178,000)	(390,506,000)
Proceeds from sale of equity method investment, net of contributions			(181,000)
Change in restricted cash			7,350,000
Additions to furniture, fixtures and equipment, net	(16,000)	(67,000)	(3,024,000)
Change in working capital related to investing activities	(4,086,000)	(66,102,000)	9,189,000
Cash used in investing activities	(23,890,000)	(217,347,000)	(377,172,000)
FINANCING ACTIVITIES:
Borrowings under credit facility	50,100,000	272,000,000	353,921,000
Repayment of amounts outstanding under credit facility	(50,100,000)	(149,000,000)	(203,921,000)
Extinguishment of senior notes		(8,722,000)
Tax withholdings related to restricted stock	(797,000)	(210,000)	(587,000)
Debt issuance costs	(197,000)		(2,174,000)
Change in working capital related to financing activities	(1,776,000)	731,000
Cash (used in) provided by financing activities	(2,770,000)	114,799,000	147,239,000
CHANGE IN CASH AND CASH EQUIVALENTS	(579,000)	168,000	(58,329,000)
CASH AND CASH EQUIVALENTS , beginning of year	600,000	432,000	58,761,000
CASH AND CASH EQUIVALENTS , end of year	21,000	600,000	432,000
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for income taxes			404,000
Cash paid for interest	25,972,000	23,634,000	20,232,000
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
Acquisition of oil and gas properties			510,000
Asset retirement obligations capitalized	$ 36,000	$ 151,000	$ 898,000

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies Organization and Nature of Operations Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin. Consolidation, Basis of Presentation and Significant Estimates The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net loss reported. Cash and Cash Equivalents We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible. Oil and Gas Properties Capitalized Costs . Our oil and gas properties comprised the following (in thousands): December 31, 2016 2015 Mineral interests in properties: Unproved leasehold costs $ 33,596 $ 37,853 Proved leasehold costs 44,643 44,122 Wells and related equipment and facilities 1,774,314 1,753,649 Support equipment 8,002 9,545 Uncompleted wells, equipment and facilities 9,219 8,612 Total costs 1,869,774 1,853,781 Less accumulated depreciation, depletion and amortization (780,412 ) (702,139 ) Net capitalized costs $ 1,089,362 $ 1,151,642 We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2016 or 2015. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2016, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income. Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $78.7 million, $108.8 million and $106.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. We recorded no impairment of our unproved properties for the years ended December 31, 2016 and 2014. Certain leases that we consider non-core to our development of Project Pangea were impaired during the year ended December 31, 2015, as we did not plan to develop them. As a result, we recorded a non-cash impairment loss of unproved property of $5.5 million for the year ended December 31, 2015. The total impairment loss of $220.2 million for the year ended December 31, 2015, is recorded in impairment of oil and gas properties on our consolidated statements of operations, and in accumulated depletion, depreciation and amortization on our consolidated balance sheets. On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. Other Property Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $343,000, $563,000 and $588,000 for the years ended December 31, 2016, 2015 and 2014, respectively. Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2016 and 2015. See Note 7 for fair value disclosures. Income Taxes We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes on the consolidated statements of operations. Based on our analysis, we did not have any uncertain tax positions as of December 31, 2016 or 2015. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2013 and forward and Texas income and margin tax returns for tax years 2013 and forward. There are currently no income tax examinations underway for these jurisdictions. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We do not currently have a valuation allowance on our federal net operating loss carryforwards (“NOLs”). Derivative Activity We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.” Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. Realized gains and losses are also included in income (expense) on our consolidated statements of operations. Accrued Liabilities The following is a summary of our accrued liabilities at December 31, 2016 and 2015 (in thousands): 2016 2015 Capital expenditures accrual $ 1,067 $ 3,476 Operating expenses and other 6,750 9,988 Total $ 7,817 $ 13,464 Asset Retirement Obligations Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014. Share-Based Compensation We measure and record compensation expense for share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations. In 2016, we awarded cash-settled performance awards, subject to certain performance conditions, to our executive officers. The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations. Earnings Per Common Share We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts): For the Years Ended December 31, 2016 2015 2014 Income (numerator): Net (loss) income — basic $ (52,243 ) $ (174,104 ) $ 56,172 Weighted average shares (denominator): Weighted average shares — basic 41,488,206 40,464,283 39,407,733 Dilution effect of share-based compensation, treasury method (1) — — 12,132 Weighted average shares — diluted 41,488,206 40,464,283 39,419,865 Net (loss) income per share: Basic $ (1.26 ) $ (4.30 ) $ 1.43 Diluted $ (1.26 ) $ (4.30 ) $ 1.42 (1) Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the years ended December 31, 2016 and 2015. Oil and Gas Operations Revenue and Accounts Receivable . We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGLs and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2016 or 2015. Accounts receivable related to oil, NGLs and gas sales includes $0.2 million and $4.8 million from realized gains on commodity derivatives at December 31, 2016 and 2015, respectively. Oil, NGLs and Gas Sales Payable. Oil, NGLs and gas sales payable represents amounts collected from purchasers for oil, NGLs and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred. Production Costs. Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expenses on our consolidated statements of operations. Exploration expenses. Exploration expenses include lease expirations, delay rentals, geological and geophysical costs and dry hole costs. For the year ended December 31, 2015 exploration expense includes $2.2 million related to the early termination of daywork drilling contracts. Dependence on Major Customers. For the year ended December 31, 2016, sales to JP Energy Development, LP (“JP Energy”) and DCP Midstream, LP (“DCP”) accounted for approximately 54% and 46%, respectively, of our total sales. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2015, sales to DCP and JP Energy accounted for approximately 36% and 63%, respectively of our total sales. For the year ended December 31, 2014, sales to DCP and JP Energy accounted for approximately 30% and 69%, respectively of our total sales. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy. Segment Reporting The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas. Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition.” This accounting standard update provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. This new guidance permits adoption through the use of either a full retrospective approach or a modified retrospective approach for annual reporting periods beginning on or after December 15, 2016, with early adoption not permitted. In August 2015, FASB delayed the effective date one year, making the new standard effective for interim periods and annual periods beginning after December 15, 2017. We have not determined which transition method we will use and are continuing to evaluate our existing revenue recognition policies to determine whether any of our contracts will be affected by the new requirements. This evaluation will continue throughout 2017, and we are currently planning to adopt this new standard in the first quarter of 2018. In September 2015, FASB issued an accounting standards update for “Business Combinations,” which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. We adopted this new guidance prospectively in the first quarter of 2016. This new guidance did not have a significant impact on the consolidated financial statements. In February 2016, FASB issued an accounting standards update for “Leases,” which amends existing guidance to require lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by long-term leases and to disclose additional quantitative and qualitative information about leasing arrangements. This new guidance is effective for interim and annual periods beginning after December 15, 2018, and we will adopt it using a modified retrospective approach. The Company is evaluating the impact of this new guidance on its consolidated financial statements. In March 2016, FASB issued an accounting standards update for “Compensation — Stock Compensation,” sing a modified retrospective approach. We have elected to (i) recognize forfeitures of share-based compensation as they occur, (ii) permit tax withholdings in excess of the minimum statutory requirements and (iii) recognize previously un-recognized excess tax benefits related to share-based compensation in the current year. As a result, we have recognized an increase in accumulated earnings in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016. Adoption of this guidance did not impact our consolidated statements of operations or cash flows. In January 2017, the FASB issued an accounting standards update for “Clarifying the Definition of a Business,” which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This standard requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. This standard is effective for interim and annual reporting periods beginning after December 15, 2016. F-1

Exchange Transactions

Exchange Transactions	12 Months Ended
	Dec. 31, 2016
Exchange Transactions [Abstract]
Exchange Transactions	2. Exchange Transactions On November 2, 2016, we entered into an exchange agreement with the largest holder of our 7% Senior Notes due 2021 (the “Senior Notes”) On January 26, 2017, our stockholders approved the Initial Exchange and an increase in our authorized common stock from 90 million shares to 180 million shares. We closed the Initial Exchange on January 27, 2017, and paid $1.1 million of accrued interest on the Senior Notes held by the exchanging noteholder. In connection with the Initial Exchange, a second supplemental indenture became effective, which removed certain covenants and events of default from the indenture governing our Senior Notes, and eliminated certain restrictive covenants discussed in Note 3. As of December 31, 2016, we have incurred approximately $2.1 million in costs related to the Initial Exchange, which are recorded in prepaid expenses and other current assets. On January 30, 2017, we offered to exchange our remaining There are no minimum subscription requirements for the Follow-On Exchange, and we cannot predict participation levels. Depending on the participation levels in the Follow-On Exchange, we may further reduce our long-term debt. Additionally, use of our federal NOLs may be limited as a result of the Follow-On Exchange.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	3. Long-Term Debt The following table provides a summary of our long-term debt at December 31, 2016, and December 31, 2015 (in thousands). December 31, 2016 December 31, 2015 Senior secured credit facility: Outstanding borrowings $ 273,000 $ 273,000 Debt issuance costs (1,304 ) (2,252 ) Senior secured credit facility, net 271,696 270,748 Senior notes: Principal 230,320 230,320 Debt issuance costs (3,667 ) (4,481 ) Senior notes, net 226,653 225,839 Total long-term debt $ 498,349 $ 496,587 Senior Secured Credit Facility At December 31, 2016, the borrowing base and aggregate lender commitments under our amended and restated senior secured credit facility (the “Credit Facility”) were $325 million, with maximum commitments from the lenders of $1 billion. The Credit Facility has a maturity date of May 7, 2019. The borrowing base is redetermined semi-annually based on our oil, NGLs and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year. Borrowings under the Credit Facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.50% to 2.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 2.50% to 3.50%. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available under the Credit Facility. Margins vary based on the borrowings outstanding compared to the borrowing base of the lenders. We had $273 million of outstanding borrowings under the Credit Facility at December 31, 2016 and 2015. The weighted average interest rate applicable to borrowings under the Credit Facility in 2016 was 3.3%. We also had outstanding unused letters of credit under our Credit Facility totaling $0.6 million at December 31, 2016, compared to $0.3 million at December 31, 2015, which reduce amounts available for borrowing under the Credit Facility. Obligations under the Credit Facility are secured by mortgages on substantially all of the oil and gas properties of the Company and its subsidiaries. The Company is required to grant liens in favor of the lenders covering the oil and gas properties of the Company and its subsidiaries representing at least 90% of the total value of all oil and gas properties of the Company and its subsidiaries. On May 3, 2016, we entered into a third amendment to the Credit Facility. The third amendment, among other things, (a) decreased the borrowing base to million from $450 million, (b) to cash Interest Expense (as defined in the Credit Facility) to 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness), through December 31, 2017, 1.5 to 1.0 through December 31, 2018, and 2.0 to 1.0 thereafter; (c) increased the applicable margin rates on borrowings by 100 basis points, (d) permits the Company to issue up to $150 million of second lien indebtedness, subject to various conditions and limitations, (e) permits the Company to repurchase outstanding debt with proceeds of certain asset sales, equity issuances or second lien indebtedness, and (f) requires cash and cash equivalents in excess of $35 million held by the Company to be applied to reduce outstanding borrowings under the Credit Facility. Covenants The Credit Facility contains two principal financial covenants: • a consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to cash Interest Expense (as defined in the Credit Facility) as of the last day of any fiscal quarter of not less than 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness) • a consolidated modified current ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Credit Facility also contains covenants restricting cash distributions and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investment in other entities and liens on properties. In addition, the obligations of the Company may be accelerated upon the occurrence of an Event of Default (as defined in the Credit Facility). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as defined in the Credit Facility), which includes instances where a third party becomes the beneficial owner of more than 50% of the Company’s outstanding equity interests entitled to vote. Senior Notes In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”). Annual interest on the Senior Notes is payable semi-annually on June 15 and December 15. On December 15, 2016, we made a semi-annual interest payment of $8.1 million. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under the Credit Facility, fund our capital expenditures for the development of our Wolfcamp shale oil resource play and for general working capital needs. During the year ended December 31, 2015, we repurchased Senior Notes in the open market with an aggregate face value of $19.7 million for a purchase price of $8.8 million, including accrued interest. This resulted in a gain on extinguishment of debt of $10.6 million. On November 2, 2016, we entered into the Initial Exchange. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our Senior Notes outstanding by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our debt and improve our operating cash flow through the reduction of interest expense. We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wilmington Trust, National Association, as successor trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.” On December 20, 2016, we entered into the second supplemental indenture (the “Second Supplemental Indenture”), which became effective in connection with the closing of the Initial Exchange. The Second Supplemental Indenture (i) eliminated certain definitions and references to definitions contained in the Indenture; (ii) eliminated and revised, as applicable, certain events of default contained in the Indenture; (iii) eliminated certain conditions to consolidation, merger, conveyance, transfer or lease contained in the Indenture; (iv) eliminated certain covenants contained in the Indenture, including substantially all of the restrictive covenants set forth therein; and (v) supplemented and amended the Senior Notes and the securities guarantees, as and to the same extent as the Indenture has been amended and supplemented in accordance with the preceding clauses (i), (ii), (iii) and (iv). We may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee: • in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the Indenture; • in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the Indenture; • if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the Indenture; • upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the indenture, in each case, in accordance with the Indenture; • upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the indenture as a result thereof or shall have occurred and is continuing; or • in the case of any restricted subsidiary that, after the issue date of the notes is required under the indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under the revolving credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (i) guarantee of such indebtedness or (ii) obligation under such revolving credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes. As a result of the Second Supplemental Indenture, the Indenture contains limited events of default. Subsidiary Guarantors The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise. At December 31, 2016, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

Termination Costs

Termination Costs	12 Months Ended
	Dec. 31, 2016
Restructuring And Related Activities [Abstract]
Termination Costs	4. Termination Costs In September 2015, we reduced our workforce to decrease costs and better align our workforce with the needs of the business and oil and gas prices. In connection with the reduction, we incurred $1.4 million in expenses, which was recorded in termination costs on our consolidated statements of operations. As of December 31, 2016, $0.3 million in termination costs is recorded in current liabilities on our consolidated balance sheets. We also recorded a benefit of $0.3 million in share-based compensation expense related to the forfeiture of unvested shares of restricted stock in connection with our workforce reduction, which was recorded in general and administrative expense on our consolidated statements of operations.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-Based Compensation	5. Share-Based Compensation In June 2007, our board of directors and stockholders approved the 2007 Stock Incentive Plan (the “2007 Plan”). Under the 2007 Plan, we may grant restricted stock, stock options, stock appreciation rights, restricted stock units, performance awards, unrestricted stock awards and other incentive awards. Under a Fifth Amendment to the 2007 Plan effective June 2, 2016, the maximum number of shares of common stock available for the grant of awards under the 2007 Plan after June 2, 2016, is 6,125,000. Awards of any stock options are to be priced at not less than the fair market value at the date of the grant. We use (i) the closing stock price on the date of grant for the fair value of restricted stock awards, including performance-based awards, (ii) the Monte Carlo simulation method for the fair value of market-based awards, (iii) the fair market value of our common stock on the valuation date for cash-settled performance awards and (iv) the Black-Scholes option price model to measure the fair value of stock options. The vesting period of any stock award is to be determined by the board or an authorized committee at the time of the grant. Share-based compensation expense amounted to $6.3 million, $8 million and $8.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Such amounts represent the estimated fair value of stock awards for which the requisite service period elapsed during those periods. Included in share-based compensation expense in 2014 was a benefit of $1.1 million for forfeited stock awards related to the retirement of one of our executive officers. Share-based compensation expense for the years ended December 31, 2016, 2015 and 2014, included $214,000, $735,000 and $749,000, respectively, related to grants to non-employee directors. Stock Options There were no stock option grants during the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016, 38,525 options were fully vested and outstanding with a weighted average exercise price of $12.00 and a weighted average remaining contractual term of 0.85 years. There were no options exercised during the years ended December 31, 2016, 2015 and 2014. Nonvested Shares Share grants totaling 1,318,229 shares, 1,278,329 shares and 992,919 shares with an approximate aggregate fair market value of $2.5 million, $6.2 million and $14.4 million, based on the closing price of our common stock on the date of grant, were granted to employees and non-employee directors during the years ended December 31, 2016, 2015 and 2014, respectively. Included in the share grants for 2016, 2015 and 2014, are 550,272 shares, 724,249 shares and 245,157 shares, respectively, awarded to our executive officers. The aggregate fair market value of these shares on the grant date was $0.3 million, $4.5 million and $4.5 million, respectively, to be expensed over a service period of approximately three years, subject to certain performance restrictions. The share grants for executive officers noted above does not include the cash-settled performance awards, which are discussed in more detail below. A summary of the status of nonvested shares for the years ended December 31, 2016, 2015 and 2014, is presented below: Shares Weighted Average Grant-Date Fair Value Nonvested at January 1, 2014 699,231 $ 23.70 Granted 992,919 14.48 Vested (400,429 ) 20.18 Canceled (169,311 ) 25.57 Nonvested at December 31, 2014 1,122,410 $ 16.52 Granted 1,278,329 4.87 Vested (419,222 ) 15.26 Canceled (246,261 ) 14.30 Nonvested at December 31, 2015 1,735,256 $ 8.60 Granted 1,318,229 1.90 Vested (992,461 ) 7.03 Canceled (107,960 ) 17.33 Nonvested at December 31, 2016 1,953,064 $ 4.39 As of December 31, 2016, unrecognized compensation expense related to the nonvested shares amounted to $4 million, which will be recognized over a remaining service period of two years. Cash-settled performance awards In 2016, in addition to the share grants discussed above, we awarded 1,100,543 cash-settled performance awards, subject to certain performance conditions, to our executive officers. The aggregate fair market value of the cash-settled shares on the grant date was approximately $1 million, to be expensed over a remaining service period of approximately three years, subject to performance conditions. The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured, based on the fair market value of our common stock, at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations. For the year ended December 31, 2016, we recognized $1.3 million in expense related to the cash-settled performance awards, recorded as a current liability of $0.6 million and a non-current liability of $0.7 million on our consolidated balance sheet. Subsequent Restricted Share Award Subsequent to December 31, 2016, 1,443,256 restricted shares were awarded to our executive officers, of which 962,171 shares are subject to certain performance conditions and 481,085 shares are subject to three-year total shareholder return (“TSR”) conditions, assuming maximum TSR. The aggregate fair market value of the shares on the grant date was approximately $2.9 million, to be expensed over a remaining service period of approximately three years. Employee Benefit Plan The Company has a defined contribution employee benefit plan covering substantially all of its employees. We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation. The Company made contributions to the plan of approximately $338,000, $404,000 and $310,000 during the years ended December 31, 2016, 2015 and 2014, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	6. Income Taxes Our provision for income taxes comprised the following (in thousands): Years Ended December 31, 2016 2015 2014 Current: Federal $ — $ (265 ) $ (25 ) State — — — Total current provision for income taxes $ — $ (265 ) $ (25 ) Deferred: Federal $ (24,957 ) $ (91,716 ) $ 32,754 State 539 (1,424 ) 963 Total deferred provision for income taxes $ (24,418 ) $ (93,140 ) $ 33,717 Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands): Years Ended December 31, 2016 2015 2014 Statutory tax at 35% $ (26,831 ) $ (93,628 ) $ 31,452 State taxes, net of federal impact 578 (1,463 ) 989 Share-based compensation tax shortfall 1,826 1,939 1,670 Permanent differences 11 26 37 Other differences (2 ) (1,035 ) (456 ) Valuation allowance — 756 — Total $ (24,418 ) $ (93,405 ) $ 33,692 In 2016, 2015 and 2014, the Company recorded a tax shortfall related to share-based compensation of $1.8 million, $1.9 million and $1.7 million, respectively. This shortfall is for grants in which the realized tax deduction was less than the expense booked for these grants due to a decline in share price from the time of grant. In 2016, we early adopted accounting standards update for “Compensation — Stock Compensation.” As a result, we have recognized an increase in accumulated earnings and our NOLs in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016. Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax basis of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a long-term liability of $5.6 million and $31.8 million at December 31, 2016 and 2015, respectively. Significant components of net deferred tax assets and liabilities are (in thousands): Years Ended December 31, 2016 2015 Deferred tax assets: Net operating loss carryforwards $ 155,018 $ 88,230 Unrealized loss on commodity derivatives 1,732 — Other 892 1,672 Total deferred tax assets 157,642 89,902 Deferred tax liabilities: Difference in depreciation, depletion and capitalization methods — oil and gas properties (162,501 ) (118,534 ) Unrealized gain on commodity derivatives — (2,391 ) Total deferred tax liabilities (162,501 ) (120,925 ) Valuation allowance (756 ) (756 ) Net deferred tax liability $ (5,615 ) $ (31,779 ) Our NOLs have the following expiration dates (in thousands): Expiration Dates Amounts 2030 $ 5,790 2031 19,686 2032 54,714 2033 78 2034 56,505 2035 116,482 2036 189,649 Total $ 442,904 A change in ownership of our common stock by more than 50% within a three-year period would result in a substantial portion of our NOLs being eliminated or becoming restricted, and we would need to reduce our deferred tax assets to reflect the restricted use of these NOLs when such an ownership change occurs. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change, multiplied by the federal long-term tax exempt rate for the month of the ownership change. We do not believe that the Initial Exchange resulted in a change of ownership of 50% or more of common stock over the applicable period; however, the Follow-On Exchange may result in such an ownership change. If such an ownership change occurs, use of our NOLs as of December 31, 2016 could be limited.

Derivative Instruments and Fair

Derivative Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Fair Value Measurements	7. Derivative Instruments and Fair Value Measurements At December 31, 2016, we had the following commodity derivatives positions outstanding: Commodity and Period Contract Type Volume Transacted Contract Price Natural Gas January 2017 — March 2017 Swap 100,000 MMBtu/month $2.463/MMBtu January 2017 — March 2017 Swap 300,000 MMBtu/month $2.45/MMBtu January 2017 — March 2017 Swap 200,000 MMBtu/month $3.287/MMBtu January 2017 — December 2017 Collar 100,000 MMBtu/month $3.00/MMBtu - $3.65/MMBtu April 2017 — December 2017 Collar 200,000 MMBtu/month $2.30/MMBtu - $2.60/MMBtu April 2017 — December 2017 Collar 200,000 MMBtu/month $3.00/MMBtu - $3.44/MMBtu April 2017 — December 2017 Collar 200,000 MMBtu/month $3.00/MMBtu - $3.50/MMBtu After December 31, 2016, we entered into the following commodity derivative positions: Commodity and Period Contract Type Volume Transacted Contract Price Natural Gas January 2018 — December 2018 Swap 200,000 MMBtu/month $3.085/MMBtu January 2018 — December 2018 Swap 250,000 MMBtu/month $3.084/MMBtu NGLs (C2 - Ethane) February 2017 — December 2017 Swap 1,050 Bbls/day $11.34/Bbl NGLs (C3 - Propane) February 2017 — December 2017 Swap 750 Bbls/day $27.916/Bbl NGLs (IC4 - Isobutane) February 2017 — December 2017 Swap 75 Bbls/day $36.7325/Bbl NGLs (NC4 - Butane) February 2017 — December 2017 Swap 250 Bbls/day $35.9205/Bbl The following summarizes the fair value of our open commodity derivatives as of December 31, 2016 and 2015 (in thousands): Balance Sheet Location Fair Value December 31, 2016 December 31, 2015 Derivatives not designated as hedging instruments Commodity derivatives Unrealized (loss) gain on commodity derivatives $ (4,880 ) $ 6,737 The following summarizes the change in the fair value of our commodity derivatives (in thousands): Income Statement Location Year Ended December 31, 2016 2015 2014 Derivatives not designated as hedging instruments Commodity derivatives Unrealized (loss) gain on commodity derivatives $ (11,616 ) $ (33,214 ) $ 42,113 Realized gain on commodity derivatives 6,132 52,489 2,359 $ (5,484 ) $ 19,275 $ 44,472 Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. We estimate the fair value of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in income (expense) on our consolidated statements of operations. We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. To estimate the fair value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: • Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2016, we had no Level 1 measurements. • Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2016, all of our commodity derivatives were valued using Level 2 measurements. • Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. The fair value of oil and gas properties used in estimating our recognized impairment loss in 2015 represents a nonrecurring Level 3 measurement. At December 31, 2016, we had no Level 3 measurements. Nonrecurring Fair Value Measurements We recorded no impairment of our proved properties for the year ended December 31, 2016. Due to the impact of the decline in forward commodity prices during the year ended December 31, 2015, there were indications that the carrying values of certain of our oil and gas properties may be impaired and undiscounted cash flows attributable to these assets indicated their carrying amounts were not expected to be recovered. For the year ended December 31, 2015, we recognized an impairment loss of $214.7 million related primarily to our vertical Canyon wells, due to the impact of the decline in forward commodity prices. At September 30, 2015, we had $22 million in value recorded for these properties, which was the estimated fair value. We estimated the fair value of the proved oil and gas properties and equipment using a discounted cash flow model, which is a Level 3 fair value measurement. Significant inputs used to determine the fair value include estimates of (i) future sales prices for oil and gas based on NYMEX strip prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) future oil and gas reserves to be recovered and the timing thereof, and (vi) discount rates. Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands). December 31, 2016 Carrying Amount Fair Value Senior Notes, net $ 226,653 $ 206,286 The fair value of the Senior Notes is based on quoted market prices, but the Senior Notes are not actively traded in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	8. Commitments and Contingencies At December 31, 2016, we had outstanding employment agreements with all four of our executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, resigned for good reason, or received a notice of non-renewal was approximately $5.7 million at December 31, 2016. This estimate assumes the maximum potential bonus for 2017 is earned by each executive officer during 2017. In 2017, we amended the employment agreements with two of our executive officers, which among other things, increased the maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, by approximately $0.6 million. In 2016, we recorded a contractual settlement of $1.4 million, which is recorded in other income on our consolidated statements of operations. We lease our office space in Fort Worth, Texas, under a non-cancelable agreement that expires on March 31, 2020. In January 2017, we amended our lease to reduce the aggregate leased space by approximately 5,500 square feet and extended the term to September 30, 2021. This amendment reduced our contractual obligations by approximately $0.4 million during the next three years, while increasing our total contractual obligations by $0.9 million over the extended term of the lease. We also have non-cancelable operating lease commitments related to office equipment that expire by 2021. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2016 (in thousands): 2017 $ 989 2018 979 2019 980 2020 248 2021 2 Total $ 3,198 Rent expense under our lease arrangements amounted to $1,025,000, $1,002,000 and $717,000 for the years ended December 31, 2016, 2015 and 2014, respectively. Litigation We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows. In 2016, we received $1.1 million from a service provider in a legal settlement, which reduced our current liabilities on our consolidated balance sheets and is recorded as a reduction in additions to oil and gas properties on our consolidated statements of cash flows. Environmental Issues We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental clean up of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. No claim has been made, nor are we aware of any liability that exists, as it relates to any environmental clean up, restoration, contamination or the violation of any rules or regulations relating thereto.

Oil and Gas Producing Activitie

Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Oil and Gas Producing Activities	9. Oil and Gas Producing Activities Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands): For the Years Ended December 31, 2016 2015 2014 Property acquisition costs: Unproved properties $ 17 $ 653 $ 4,578 Proved properties — — — Exploration costs 3,923 4,439 3,831 Development costs(1) 15,884 146,237 382,995 Total costs incurred $ 19,824 $ 151,329 $ 391,404 (1) For the years ended December 31, 2016, 2015 and 2014, development costs included $36,000, $151,000 and $898,000, respectively, in non-cash asset retirement obligations. Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands): For the Years Ended December 31, 2016 2015 2014 Revenues $ 90,302 $ 131,336 $ 258,529 Production costs (27,467 ) (40,057 ) (48,635 ) Exploration expense (3,923 ) (4,439 ) (3,831 ) Depletion (79,044 ) (109,319 ) (106,802 ) Impairment of oil and gas properties — (220,197 ) — Income tax benefit (expense) 7,144 86,120 (35,387 ) Results of operations $ (12,988 ) $ (156,556 ) $ 63,874

Disclosures About Oil and Gas P

Disclosures About Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Disclosures About Oil and Gas Producing Activities (unaudited)	10. Disclosures About Oil and Gas Producing Activities (unaudited) Proved Reserves All of our estimated oil and natural gas reserves are attributable to properties within the United States, primarily in the Permian Basin in West Texas. The estimates of proved reserves and related valuations for the years ended December 31, 2016, 2015 and 2014, were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current rules and guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. The following table summarizes the prices used in the reserve estimates for 2016, 2015 and 2014. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows: 2016 2015 2014 Oil (per Bbl) $ 42.69 $ 50.16 $ 94.56 Natural gas liquids (per Bbl) $ 14.12 $ 15.13 $ 31.50 Gas (per Mcf) $ 2.47 $ 2.64 $ 4.55 Oil, NGLs and natural gas reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2016, 2015 and 2014, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year. Total Proved Reserves Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Balance — January 1, 2014 46,067 32,593 216,002 114,661 Extensions and discoveries 19,347 10,658 79,454 43,247 Production(1) (2,024 ) (1,461 ) (10,773 ) (5,281 ) Revisions to previous estimates (8,052 ) (883 ) 15,337 (6,379 ) Balance — December 31, 2014 55,338 40,907 300,020 146,248 Extensions and discoveries 11,054 10,630 79,268 34,895 Production(1) (1,882 ) (1,694 ) (13,262 ) (5,787 ) Revisions to previous estimates (10,014 ) (357 ) 9,962 (8,710 ) Balance — December 31, 2015 54,496 49,486 375,988 166,646 Extensions and discoveries 6,529 4,564 33,347 16,651 Production(1) (1,275 ) (1,529 ) (11,734 ) (4,759 ) Revisions to previous estimates (9,719 ) (4,887 ) (45,324 ) (22,161 ) Balance — December 31, 2016 50,031 47,634 352,277 156,377 (1) Production included 1,390 MMcf, 1,530 MMcf and 1,330 MMcf related to field fuel in 2014, 2015 and 2016, respectively. Total Proved Reserves Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Proved Developed Reserves: January 1, 2014 13,646 14,919 99,742 45,189 December 31, 2014 17,978 19,082 138,961 60,220 December 31, 2015 15,667 20,414 154,652 61,856 December 31, 2016 13,466 20,375 150,208 58,875 Proved Undeveloped Reserves: January 1, 2014 32,421 17,674 116,260 69,472 December 31, 2014 37,360 21,825 161,059 86,028 December 31, 2015 38,829 29,072 221,335 104,790 December 31, 2016 36,565 27,259 202,069 97,502 The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2016, 2015 and 2014: Year Ended December 31, 2016 Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices. We produced 4.8 MMBoe during 2016. This production included 1,330 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point. Year Ended December 31, 2015 Extensions and discoveries for 2015 were 34.9 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2015, we reclassified 11.9 MMBoe of proved reserves to unproved reserves. The reserves reclassified are attributable to horizontal and vertical well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 13 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 9.8 MMBoe due to lower commodity prices. We produced 5.8 MMBoe during 2015. This production included 1,530 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point. Year Ended December 31, 2014 Extensions and discoveries for 2014 were 43.2 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2014, we reclassified 9.3 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified included 5.8 MMBoe attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking, and 3.5 MMBoe attributable to horizontal Wolfcamp locations that are no longer included in our proved development plan. Revisions included an increase of 6.3 MMBoe attributable to updated well performance and an increase of 0.7 MMBoe due to pricing, offset by a decrease of 4.1 MMBoe resulting from updated technical parameters and costs. We produced 5.3 MMBoe during 2014. This production included 1,390 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference. Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise. The following table provides the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014 (in thousands): Years Ended December 31, 2016 2015 2014 Future cash flows $ 3,319,551 $ 4,097,568 $ 7,430,368 Future production costs (1,054,211 ) (1,237,888 ) (1,704,333 ) Future development costs (829,926 ) (934,814 ) (1,247,446 ) Future income tax expense (132,834 ) (307,374 ) (1,267,025 ) Future net cash flows 1,302,580 1,617,492 3,211,564 10% annual discount for estimated timing of cash flows (1,004,825 ) (1,157,097 ) (2,155,749 ) Standardized measure of discounted future net cash flows $ 297,755 $ 460,395 $ 1,055,815 Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end. Changes in Standardized Measure of Discounted Future Net Cash Flows The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): Years Ended December 31, 2016 2015 2014 Balance, beginning of period $ 460,395 $ 1,055,815 $ 676,277 Net change in sales and transfer prices and in production (lifting) costs related to future production (191,841 ) (1,405,864 ) (59,920 ) Changes in estimated future development costs 17,405 231,900 (388,772 ) Sales and transfers of oil and gas produced during the period (62,835 ) (91,278 ) (209,893 ) Net change due to extensions, discoveries and improved recovery 13,988 156,783 534,231 Net change due to revisions in quantity estimates (25,236 ) (59,305 ) (78,801 ) Previously estimated development costs incurred during the period 15,884 146,237 382,995 Accretion of discount 46,040 105,582 113,188 Other (9,500 ) 6,915 (11,897 ) Net change in income taxes 33,455 313,610 98,407 Standardized Measure of discounted future net cash flows $ 297,755 $ 460,395 $ 1,055,815

Supplementary Data

Supplementary Data	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Supplementary Data	11. Supplementary Data Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts): 2016 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 26,505 $ 23,749 $ 22,433 $ 17,615 Net operating expenses (33,564 ) (32,201 ) (34,534 ) (34,869 ) Interest expense, net (7,086 ) (7,067 ) (6,808 ) (6,298 ) Write-off of debt issuance costs — — (563 ) — Realized gain on commodity derivatives 442 781 1,409 3,500 Unrealized (loss) gain on commodity derivatives (3,343 ) 760 (8,076 ) (957 ) Other income (expense) — (10 ) 1,417 104 Loss before income tax benefit (17,046 ) (13,988 ) (24,722 ) (20,905 ) Income tax benefit (3,571 ) (4,915 ) (8,687 ) (7,245 ) Net loss $ (13,475 ) $ (9,073 ) $ (16,035 ) $ (13,660 ) Basic net loss applicable to common stockholders per common share $ (0.32 ) $ (0.22 ) $ (0.39 ) $ (0.33 ) Diluted net loss applicable to common stockholders per common share $ (0.32 ) $ (0.22 ) $ (0.39 ) $ (0.33 ) 2015 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 25,492 $ 33,941 $ 38,605 $ 33,298 Net operating expenses (38,671 ) (272,462 ) (46,970 ) (45,686 ) Interest expense, net (6,436 ) (6,465 ) (6,243 ) (5,922 ) Gain on debt extinguishment 9,080 1,483 — — Realized gain on commodity derivatives 14,552 12,755 9,281 15,901 Unrealized (loss) gain on commodity derivatives (10,285 ) 296 (13,904 ) (9,321 ) Other income (expense) 225 (91 ) 12 26 Loss before income tax benefit (6,043 ) (230,543 ) (19,219 ) (11,704 ) Income tax benefit (284 ) (81,756 ) (7,369 ) (3,996 ) Net loss $ (5,759 ) $ (148,787 ) $ (11,850 ) $ (7,708 ) Basic net loss applicable to common stockholders per common share $ (0.14 ) $ (3.67 ) $ (0.29 ) $ (0.19 ) Diluted net loss applicable to common stockholders per common share $ (0.14 ) $ (3.67 ) $ (0.29 ) $ (0.19 ) 2014 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 55,070 $ 68,124 $ 73,408 $ 61,927 Net operating expenses (50,136 ) (45,525 ) (50,812 ) (44,899 ) Interest expense, net (5,715 ) (5,442 ) (5,357 ) (5,137 ) Equity in earnings (losses) of investee 5 — (186 ) — Realized gain (loss) on commodity derivatives 7,782 (764 ) (3,320 ) (1,339 ) Unrealized gain (loss) on commodity derivatives 36,907 18,810 (7,678 ) (5,926 ) Other income (expense) 176 — (109 ) — Income before income tax 44,089 35,203 5,946 4,626 Income tax provision 17,102 12,756 2,153 1,681 Net income $ 26,987 $ 22,447 $ 3,793 $ 2,945 Basic net income applicable to common stockholders per common share $ 0.68 $ 0.57 $ 0.10 $ 0.08 Diluted net income applicable to common stockholders per common share $ 0.68 $ 0.57 $ 0.10 $ 0.08

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin.
Consolidation, Basis of Presentation and Significant Estimates	Consolidation, Basis of Presentation and Significant Estimates The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net loss reported.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.
Capitalized Costs	Capitalized Costs . Our oil and gas properties comprised the following (in thousands): December 31, 2016 2015 Mineral interests in properties: Unproved leasehold costs $ 33,596 $ 37,853 Proved leasehold costs 44,643 44,122 Wells and related equipment and facilities 1,774,314 1,753,649 Support equipment 8,002 9,545 Uncompleted wells, equipment and facilities 9,219 8,612 Total costs 1,869,774 1,853,781 Less accumulated depreciation, depletion and amortization (780,412 ) (702,139 ) Net capitalized costs $ 1,089,362 $ 1,151,642 We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2016 or 2015. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2016, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income. Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $78.7 million, $108.8 million and $106.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. We recorded no impairment of our unproved properties for the years ended December 31, 2016 and 2014. Certain leases that we consider non-core to our development of Project Pangea were impaired during the year ended December 31, 2015, as we did not plan to develop them. As a result, we recorded a non-cash impairment loss of unproved property of $5.5 million for the year ended December 31, 2015. The total impairment loss of $220.2 million for the year ended December 31, 2015, is recorded in impairment of oil and gas properties on our consolidated statements of operations, and in accumulated depletion, depreciation and amortization on our consolidated balance sheets. On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. F-1
Other Property	Other Property Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $343,000, $563,000 and $588,000 for the years ended December 31, 2016, 2015 and 2014, respectively.
Financial Instruments	Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2016 and 2015. See Note 7 for fair value disclosures.
Income Taxes	Income Taxes We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes on the consolidated statements of operations. Based on our analysis, we did not have any uncertain tax positions as of December 31, 2016 or 2015. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2013 and forward and Texas income and margin tax returns for tax years 2013 and forward. There are currently no income tax examinations underway for these jurisdictions. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We do not currently have a valuation allowance on our federal net operating loss carryforwards (“NOLs”).
Derivative Activity	Derivative Activity We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.” Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in income (expense) on our consolidated statements of operations. Realized gains and losses are also included in income (expense) on our consolidated statements of operations.
Accrued Liabilities	Accrued Liabilities The following is a summary of our accrued liabilities at December 31, 2016 and 2015 (in thousands): 2016 2015 Capital expenditures accrual $ 1,067 $ 3,476 Operating expenses and other 6,750 9,988 Total $ 7,817 $ 13,464
Asset Retirement Obligations	Asset Retirement Obligations Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014.
Share-Based Compensation	Share-Based Compensation We measure and record compensation expense for share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations. In 2016, we awarded cash-settled performance awards, subject to certain performance conditions, to our executive officers. The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations.
Earnings Per Common Share	Earnings Per Common Share We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts): For the Years Ended December 31, 2016 2015 2014 Income (numerator): Net (loss) income — basic $ (52,243 ) $ (174,104 ) $ 56,172 Weighted average shares (denominator): Weighted average shares — basic 41,488,206 40,464,283 39,407,733 Dilution effect of share-based compensation, treasury method (1) — — 12,132 Weighted average shares — diluted 41,488,206 40,464,283 39,419,865 Net (loss) income per share: Basic $ (1.26 ) $ (4.30 ) $ 1.43 Diluted $ (1.26 ) $ (4.30 ) $ 1.42 (1) Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the years ended December 31, 2016 and 2015.
Revenue and Accounts Receivable from Purchasers and Joint Interest Owners	Revenue and Accounts Receivable . We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGLs and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2016 or 2015. Accounts receivable related to oil, NGLs and gas sales includes $0.2 million and $4.8 million from realized gains on commodity derivatives at December 31, 2016 and 2015, respectively.
Oil and Gas Sales Payable	Oil, NGLs and Gas Sales Payable. Oil, NGLs and gas sales payable represents amounts collected from purchasers for oil, NGLs and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.
Production Costs	Production Costs. Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense s on our consolidated statements of operations.
Exploration expenses	Exploration expenses. Exploration expenses include lease expirations, delay rentals, geological and geophysical costs and dry hole costs. For the year ended December 31, 2015 exploration expense includes $ 2.2 million related to the early termination of daywork drilling contracts.
Dependence on Major Customer	Dependence on Major Customers. For the year ended December 31, 2016, sales to JP Energy Development, LP (“JP Energy”) and DCP Midstream, LP (“DCP”) accounted for approximately 54% and 46%, respectively, of our total sales. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2015, sales to DCP and JP Energy accounted for approximately 36% and 63%, respectively of our total sales. For the year ended December 31, 2014, sales to DCP and JP Energy accounted for approximately 30% and 69%, respectively of our total sales. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.
Segment Reporting	Segment Reporting The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition.” This accounting standard update provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. This new guidance permits adoption through the use of either a full retrospective approach or a modified retrospective approach for annual reporting periods beginning on or after December 15, 2016, with early adoption not permitted. In August 2015, FASB delayed the effective date one year, making the new standard effective for interim periods and annual periods beginning after December 15, 2017. We have not determined which transition method we will use and are continuing to evaluate our existing revenue recognition policies to determine whether any of our contracts will be affected by the new requirements. This evaluation will continue throughout 2017, and we are currently planning to adopt this new standard in the first quarter of 2018. In September 2015, FASB issued an accounting standards update for “Business Combinations,” which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. We adopted this new guidance prospectively in the first quarter of 2016. This new guidance did not have a significant impact on the consolidated financial statements. In February 2016, FASB issued an accounting standards update for “Leases,” which amends existing guidance to require lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by long-term leases and to disclose additional quantitative and qualitative information about leasing arrangements. This new guidance is effective for interim and annual periods beginning after December 15, 2018, and we will adopt it using a modified retrospective approach. The Company is evaluating the impact of this new guidance on its consolidated financial statements. In March 2016, FASB issued an accounting standards update for “Compensation — Stock Compensation,” sing a modified retrospective approach. We have elected to (i) recognize forfeitures of share-based compensation as they occur, (ii) permit tax withholdings in excess of the minimum statutory requirements and (iii) recognize previously un-recognized excess tax benefits related to share-based compensation in the current year. As a result, we have recognized an increase in accumulated earnings in the current year of $1.7 million related to the change in accounting principal as of January 1, 2016. Adoption of this guidance did not impact our consolidated statements of operations or cash flows. In January 2017, the FASB issued an accounting standards update for “Clarifying the Definition of a Business,” which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This standard requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. This standard is effective for interim and annual reporting periods beginning after December 15, 2016.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Oil and Gas Properties	Our oil and gas properties comprised the following (in thousands): December 31, 2016 2015 Mineral interests in properties: Unproved leasehold costs $ 33,596 $ 37,853 Proved leasehold costs 44,643 44,122 Wells and related equipment and facilities 1,774,314 1,753,649 Support equipment 8,002 9,545 Uncompleted wells, equipment and facilities 9,219 8,612 Total costs 1,869,774 1,853,781 Less accumulated depreciation, depletion and amortization (780,412 ) (702,139 ) Net capitalized costs $ 1,089,362 $ 1,151,642
Summary of Accrued Liabilities	The following is a summary of our accrued liabilities at December 31, 2016 and 2015 (in thousands): 2016 2015 Capital expenditures accrual $ 1,067 $ 3,476 Operating expenses and other 6,750 9,988 Total $ 7,817 $ 13,464
Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share	The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts): For the Years Ended December 31, 2016 2015 2014 Income (numerator): Net (loss) income — basic $ (52,243 ) $ (174,104 ) $ 56,172 Weighted average shares (denominator): Weighted average shares — basic 41,488,206 40,464,283 39,407,733 Dilution effect of share-based compensation, treasury method (1) — — 12,132 Weighted average shares — diluted 41,488,206 40,464,283 39,419,865 Net (loss) income per share: Basic $ (1.26 ) $ (4.30 ) $ 1.43 Diluted $ (1.26 ) $ (4.30 ) $ 1.42 (1) Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the years ended December 31, 2016 and 2015.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long Term Debt	The following table provides a summary of our long-term debt at December 31, 2016, and December 31, 2015 (in thousands). December 31, 2016 December 31, 2015 Senior secured credit facility: Outstanding borrowings $ 273,000 $ 273,000 Debt issuance costs (1,304 ) (2,252 ) Senior secured credit facility, net 271,696 270,748 Senior notes: Principal 230,320 230,320 Debt issuance costs (3,667 ) (4,481 ) Senior notes, net 226,653 225,839 Total long-term debt $ 498,349 $ 496,587

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Status of Nonvested Shares	A summary of the status of nonvested shares for the years ended December 31, 2016, 2015 and 2014, is presented below: Shares Weighted Average Grant-Date Fair Value Nonvested at January 1, 2014 699,231 $ 23.70 Granted 992,919 14.48 Vested (400,429 ) 20.18 Canceled (169,311 ) 25.57 Nonvested at December 31, 2014 1,122,410 $ 16.52 Granted 1,278,329 4.87 Vested (419,222 ) 15.26 Canceled (246,261 ) 14.30 Nonvested at December 31, 2015 1,735,256 $ 8.60 Granted 1,318,229 1.90 Vested (992,461 ) 7.03 Canceled (107,960 ) 17.33 Nonvested at December 31, 2016 1,953,064 $ 4.39

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	Our provision for income taxes comprised the following (in thousands): Years Ended December 31, 2016 2015 2014 Current: Federal $ — $ (265 ) $ (25 ) State — — — Total current provision for income taxes $ — $ (265 ) $ (25 ) Deferred: Federal $ (24,957 ) $ (91,716 ) $ 32,754 State 539 (1,424 ) 963 Total deferred provision for income taxes $ (24,418 ) $ (93,140 ) $ 33,717
Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income	Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands): Years Ended December 31, 2016 2015 2014 Statutory tax at 35% $ (26,831 ) $ (93,628 ) $ 31,452 State taxes, net of federal impact 578 (1,463 ) 989 Share-based compensation tax shortfall 1,826 1,939 1,670 Permanent differences 11 26 37 Other differences (2 ) (1,035 ) (456 ) Valuation allowance — 756 — Total $ (24,418 ) $ (93,405 ) $ 33,692
Significant Components of Net Deferred Tax Assets and Liabilities	Significant components of net deferred tax assets and liabilities are (in thousands): Years Ended December 31, 2016 2015 Deferred tax assets: Net operating loss carryforwards $ 155,018 $ 88,230 Unrealized loss on commodity derivatives 1,732 — Other 892 1,672 Total deferred tax assets 157,642 89,902 Deferred tax liabilities: Difference in depreciation, depletion and capitalization methods — oil and gas properties (162,501 ) (118,534 ) Unrealized gain on commodity derivatives — (2,391 ) Total deferred tax liabilities (162,501 ) (120,925 ) Valuation allowance (756 ) (756 ) Net deferred tax liability $ (5,615 ) $ (31,779 )
Schedule of NOLs	Our NOLs have the following expiration dates (in thousands): Expiration Dates Amounts 2030 $ 5,790 2031 19,686 2032 54,714 2033 78 2034 56,505 2035 116,482 2036 189,649 Total $ 442,904

Derivative Instruments and Fa24

Derivative Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Commodity Derivatives Volumes and Prices	At December 31, 2016, we had the following commodity derivatives positions outstanding: Commodity and Period Contract Type Volume Transacted Contract Price Natural Gas January 2017 — March 2017 Swap 100,000 MMBtu/month $2.463/MMBtu January 2017 — March 2017 Swap 300,000 MMBtu/month $2.45/MMBtu January 2017 — March 2017 Swap 200,000 MMBtu/month $3.287/MMBtu January 2017 — December 2017 Collar 100,000 MMBtu/month $3.00/MMBtu - $3.65/MMBtu April 2017 — December 2017 Collar 200,000 MMBtu/month $2.30/MMBtu - $2.60/MMBtu April 2017 — December 2017 Collar 200,000 MMBtu/month $3.00/MMBtu - $3.44/MMBtu April 2017 — December 2017 Collar 200,000 MMBtu/month $3.00/MMBtu - $3.50/MMBtu After December 31, 2016, we entered into the following commodity derivative positions: Commodity and Period Contract Type Volume Transacted Contract Price Natural Gas January 2018 — December 2018 Swap 200,000 MMBtu/month $3.085/MMBtu January 2018 — December 2018 Swap 250,000 MMBtu/month $3.084/MMBtu NGLs (C2 - Ethane) February 2017 — December 2017 Swap 1,050 Bbls/day $11.34/Bbl NGLs (C3 - Propane) February 2017 — December 2017 Swap 750 Bbls/day $27.916/Bbl NGLs (IC4 - Isobutane) February 2017 — December 2017 Swap 75 Bbls/day $36.7325/Bbl NGLs (NC4 - Butane) February 2017 — December 2017 Swap 250 Bbls/day $35.9205/Bbl
Summary of Fair Value of Open Commodity Derivatives	The following summarizes the fair value of our open commodity derivatives as of December 31, 2016 and 2015 (in thousands): Balance Sheet Location Fair Value December 31, 2016 December 31, 2015 Derivatives not designated as hedging instruments Commodity derivatives Unrealized (loss) gain on commodity derivatives $ (4,880 ) $ 6,737
Summary of Change in Fair Value of Commodity Derivatives	The following summarizes the change in the fair value of our commodity derivatives (in thousands): Income Statement Location Year Ended December 31, 2016 2015 2014 Derivatives not designated as hedging instruments Commodity derivatives Unrealized (loss) gain on commodity derivatives $ (11,616 ) $ (33,214 ) $ 42,113 Realized gain on commodity derivatives 6,132 52,489 2,359 $ (5,484 ) $ 19,275 $ 44,472
Summary of Financial Instruments Not Recorded at Fair Value	The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands). December 31, 2016 Carrying Amount Fair Value Senior Notes, net $ 226,653 $ 206,286

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements	The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2016 (in thousands): 2017 $ 989 2018 979 2019 980 2020 248 2021 2 Total $ 3,198

Oil and Gas Producing Activit26

Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities	Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands): For the Years Ended December 31, 2016 2015 2014 Property acquisition costs: Unproved properties $ 17 $ 653 $ 4,578 Proved properties — — — Exploration costs 3,923 4,439 3,831 Development costs(1) 15,884 146,237 382,995 Total costs incurred $ 19,824 $ 151,329 $ 391,404 (1) For the years ended December 31, 2016, 2015 and 2014, development costs included $36,000, $151,000 and $898,000, respectively, in non-cash asset retirement obligations.
Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities	Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands): For the Years Ended December 31, 2016 2015 2014 Revenues $ 90,302 $ 131,336 $ 258,529 Production costs (27,467 ) (40,057 ) (48,635 ) Exploration expense (3,923 ) (4,439 ) (3,831 ) Depletion (79,044 ) (109,319 ) (106,802 ) Impairment of oil and gas properties — (220,197 ) — Income tax benefit (expense) 7,144 86,120 (35,387 ) Results of operations $ (12,988 ) $ (156,556 ) $ 63,874

Disclosures About Oil and Gas27

Disclosures About Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation	The following table summarizes the prices used in the reserve estimates for 2016, 2015 and 2014. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows: 2016 2015 2014 Oil (per Bbl) $ 42.69 $ 50.16 $ 94.56 Natural gas liquids (per Bbl) $ 14.12 $ 15.13 $ 31.50 Gas (per Mcf) $ 2.47 $ 2.64 $ 4.55
Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves	The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2016, 2015 and 2014, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year. Total Proved Reserves Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Balance — January 1, 2014 46,067 32,593 216,002 114,661 Extensions and discoveries 19,347 10,658 79,454 43,247 Production(1) (2,024 ) (1,461 ) (10,773 ) (5,281 ) Revisions to previous estimates (8,052 ) (883 ) 15,337 (6,379 ) Balance — December 31, 2014 55,338 40,907 300,020 146,248 Extensions and discoveries 11,054 10,630 79,268 34,895 Production(1) (1,882 ) (1,694 ) (13,262 ) (5,787 ) Revisions to previous estimates (10,014 ) (357 ) 9,962 (8,710 ) Balance — December 31, 2015 54,496 49,486 375,988 166,646 Extensions and discoveries 6,529 4,564 33,347 16,651 Production(1) (1,275 ) (1,529 ) (11,734 ) (4,759 ) Revisions to previous estimates (9,719 ) (4,887 ) (45,324 ) (22,161 ) Balance — December 31, 2016 50,031 47,634 352,277 156,377 (1) Production included 1,390 MMcf, 1,530 MMcf and 1,330 MMcf related to field fuel in 2014, 2015 and 2016, respectively. Total Proved Reserves Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Proved Developed Reserves: January 1, 2014 13,646 14,919 99,742 45,189 December 31, 2014 17,978 19,082 138,961 60,220 December 31, 2015 15,667 20,414 154,652 61,856 December 31, 2016 13,466 20,375 150,208 58,875 Proved Undeveloped Reserves: January 1, 2014 32,421 17,674 116,260 69,472 December 31, 2014 37,360 21,825 161,059 86,028 December 31, 2015 38,829 29,072 221,335 104,790 December 31, 2016 36,565 27,259 202,069 97,502
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves	The following table provides the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014 (in thousands): Years Ended December 31, 2016 2015 2014 Future cash flows $ 3,319,551 $ 4,097,568 $ 7,430,368 Future production costs (1,054,211 ) (1,237,888 ) (1,704,333 ) Future development costs (829,926 ) (934,814 ) (1,247,446 ) Future income tax expense (132,834 ) (307,374 ) (1,267,025 ) Future net cash flows 1,302,580 1,617,492 3,211,564 10% annual discount for estimated timing of cash flows (1,004,825 ) (1,157,097 ) (2,155,749 ) Standardized measure of discounted future net cash flows $ 297,755 $ 460,395 $ 1,055,815
Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): Years Ended December 31, 2016 2015 2014 Balance, beginning of period $ 460,395 $ 1,055,815 $ 676,277 Net change in sales and transfer prices and in production (lifting) costs related to future production (191,841 ) (1,405,864 ) (59,920 ) Changes in estimated future development costs 17,405 231,900 (388,772 ) Sales and transfers of oil and gas produced during the period (62,835 ) (91,278 ) (209,893 ) Net change due to extensions, discoveries and improved recovery 13,988 156,783 534,231 Net change due to revisions in quantity estimates (25,236 ) (59,305 ) (78,801 ) Previously estimated development costs incurred during the period 15,884 146,237 382,995 Accretion of discount 46,040 105,582 113,188 Other (9,500 ) 6,915 (11,897 ) Net change in income taxes 33,455 313,610 98,407 Standardized Measure of discounted future net cash flows $ 297,755 $ 460,395 $ 1,055,815

Supplementary Data (Tables)

Supplementary Data (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts): 2016 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 26,505 $ 23,749 $ 22,433 $ 17,615 Net operating expenses (33,564 ) (32,201 ) (34,534 ) (34,869 ) Interest expense, net (7,086 ) (7,067 ) (6,808 ) (6,298 ) Write-off of debt issuance costs — — (563 ) — Realized gain on commodity derivatives 442 781 1,409 3,500 Unrealized (loss) gain on commodity derivatives (3,343 ) 760 (8,076 ) (957 ) Other income (expense) — (10 ) 1,417 104 Loss before income tax benefit (17,046 ) (13,988 ) (24,722 ) (20,905 ) Income tax benefit (3,571 ) (4,915 ) (8,687 ) (7,245 ) Net loss $ (13,475 ) $ (9,073 ) $ (16,035 ) $ (13,660 ) Basic net loss applicable to common stockholders per common share $ (0.32 ) $ (0.22 ) $ (0.39 ) $ (0.33 ) Diluted net loss applicable to common stockholders per common share $ (0.32 ) $ (0.22 ) $ (0.39 ) $ (0.33 ) 2015 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 25,492 $ 33,941 $ 38,605 $ 33,298 Net operating expenses (38,671 ) (272,462 ) (46,970 ) (45,686 ) Interest expense, net (6,436 ) (6,465 ) (6,243 ) (5,922 ) Gain on debt extinguishment 9,080 1,483 — — Realized gain on commodity derivatives 14,552 12,755 9,281 15,901 Unrealized (loss) gain on commodity derivatives (10,285 ) 296 (13,904 ) (9,321 ) Other income (expense) 225 (91 ) 12 26 Loss before income tax benefit (6,043 ) (230,543 ) (19,219 ) (11,704 ) Income tax benefit (284 ) (81,756 ) (7,369 ) (3,996 ) Net loss $ (5,759 ) $ (148,787 ) $ (11,850 ) $ (7,708 ) Basic net loss applicable to common stockholders per common share $ (0.14 ) $ (3.67 ) $ (0.29 ) $ (0.19 ) Diluted net loss applicable to common stockholders per common share $ (0.14 ) $ (3.67 ) $ (0.29 ) $ (0.19 ) 2014 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 55,070 $ 68,124 $ 73,408 $ 61,927 Net operating expenses (50,136 ) (45,525 ) (50,812 ) (44,899 ) Interest expense, net (5,715 ) (5,442 ) (5,357 ) (5,137 ) Equity in earnings (losses) of investee 5 — (186 ) — Realized gain (loss) on commodity derivatives 7,782 (764 ) (3,320 ) (1,339 ) Unrealized gain (loss) on commodity derivatives 36,907 18,810 (7,678 ) (5,926 ) Other income (expense) 176 — (109 ) — Income before income tax 44,089 35,203 5,946 4,626 Income tax provision 17,102 12,756 2,153 1,681 Net income $ 26,987 $ 22,447 $ 3,793 $ 2,945 Basic net income applicable to common stockholders per common share $ 0.68 $ 0.57 $ 0.10 $ 0.08 Diluted net income applicable to common stockholders per common share $ 0.68 $ 0.57 $ 0.10 $ 0.08

Summary of Significant Accoun29

Summary of Significant Accounting Policies - Summary of Oil and Gas Properties (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Mineral interests in properties:
Unproved leasehold costs	$ 33,596	$ 37,853
Proved leasehold costs	44,643	44,122
Wells and related equipment and facilities	1,774,314	1,753,649
Support equipment	8,002	9,545
Uncompleted wells, equipment and facilities	9,219	8,612
Total costs	1,869,774	1,853,781
Less accumulated depreciation, depletion and amortization	(780,412)	(702,139)
Net capitalized costs	$ 1,089,362	$ 1,151,642

Summary of Significant Accoun30

Summary of Significant Accounting Policies - Additional Information (Detail)	Jan. 02, 2016USD ($)	Dec. 31, 2016USD ($)WellSegment	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of exploratory wells capitalized | Well		0	0
Capitalized interest cost		$ 0
Depreciation depletion and amortization for oil & gas		78,700,000	$ 108,800,000	$ 106,200,000
Impairment of oil and gas properties and equipment		0	220,197,000	0
Depreciation expense for other property and equipment		$ 343,000	563,000	588,000
Tax benefit		50.00%
Uncertain tax positions		$ 0	0
Number of days in which payment is to be made		30 days
Realized gains on commodity derivatives		$ 200,000	4,800,000
Exploration expenses		$ 3,923,000	$ 4,439,000	$ 3,831,000
Number of business segment | Segment		1
New Accounting Pronouncement, Early Adoption, Effect [Member]
Summary Of Significant Accounting Policies [Line Items]
Increase in accumulated earnings	$ 1,700,000
Customer Concentration Risk [Member] | DCP Midstream, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers		46.00%	36.00%	30.00%
Customer Concentration Risk [Member] | JP Energy Permian, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers		54.00%	63.00%	69.00%
Drilling Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Exploration expenses		$ 2,200,000
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of furniture, fixtures and equipment		3 years
Minimum [Member] | Oil and Gas [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days in which payment is to be made		30 days
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of furniture, fixtures and equipment		15 years
Maximum [Member] | Oil and Gas [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days in which payment is to be made		60 days
Proved Property Impairment [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties and equipment		$ 0	$ 214,700,000
Unproved Property Impairment [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties and equipment		$ 0	$ 5,500,000	$ 0

Summary of Significant Accoun31

Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Abstract]
Capital expenditures accrual	$ 1,067	$ 3,476
Operating expenses and other	6,750	9,988
Total	$ 7,817	$ 13,464

Summary of Significant Accoun32

Summary of Significant Accounting Policies - Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Net (loss) income — basic	$ (13,475)	$ (9,073)	$ (16,035)	$ (13,660)	$ (5,759)	$ (148,787)	$ (11,850)	$ (7,708)	$ 26,987	$ 22,447	$ 3,793	$ 2,945	$ (52,243)	$ (174,104)	$ 56,172
Weighted average shares — basic													41,488,206	40,464,283	39,407,733
Dilution effect of share-based compensation, treasury method															12,132
Weighted average shares — diluted													41,488,206	40,464,283	39,419,865
Basic	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.43
Diluted	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.42

Summary of Significant Accoun33

Summary of Significant Accounting Policies - Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share (Parenthetical) (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per common share	39,000	39,000

Exchange Transactions - Additio

Exchange Transactions - Additional Information (Detail)	Jan. 30, 2017USD ($)	Jan. 27, 2017USD ($)	Nov. 02, 2016USD ($)$ / sharesshares	Jan. 26, 2017shares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015$ / sharesshares
Exchange Transactions [Line Items]
Common stock, par value | $ / shares					$ 0.01	$ 0.01
Common stock, shares authorized | shares					90,000,000	90,000,000
7% Senior Notes Due 2021 [Member]
Exchange Transactions [Line Items]
Debt exchange to common stock, principal amount			$ 130,552,000
Debt conversion, interest rate of debt			7.00%
7% Senior Notes Due 2021 [Member] | Initial Exchange [Member]
Exchange Transactions [Line Items]
Common stock, par value | $ / shares			$ 0.01
Common stock, shares authorized | shares					90,000,000
7% Senior Notes Due 2021 [Member] | Initial Exchange [Member] | Subsequent Event [Member]
Exchange Transactions [Line Items]
Common stock, shares authorized | shares				180,000,000
Debt exchange date		Jan. 27, 2017
Payments of accrued interest		$ 1,100,000
7% Senior Notes Due 2021 [Member] | Initial Exchange [Member] | Prepaid Expenses and Other Current Assets [Member]
Exchange Transactions [Line Items]
Costs related to debt exchange					$ 2,100,000
7% Senior Notes Due 2021 [Member] | Follow-On Exchange [Member] | Subsequent Event [Member]
Exchange Transactions [Line Items]
Debt exchange to common stock, remaining principal amount	$ 99,768,000
Conversion ratio of senior notes to common stock shares	0.276
Debt exchange, principal amount denominator for conversion into common stock	$ 1,000
Minimum subscription requirements	$ 0
Common Stock [Member] | 7% Senior Notes Due 2021 [Member] | Initial Exchange [Member]
Exchange Transactions [Line Items]
Debt exchange to common stock, shares issued | shares			39,165,600

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	May 03, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Senior secured credit facility, net	$ 271,696		$ 270,748
Senior notes, net	226,653		225,839
Total long-term debt	498,349		496,587
Senior Notes [Member]
Debt Instrument [Line Items]
Principal	230,320		230,320
Debt issuance costs	(3,667)		(4,481)
Senior notes, net	226,653		225,839
Senior Secured Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowings	273,000		273,000
Debt issuance costs	(1,304)	$ (200)	(2,252)
Senior secured credit facility, net	$ 271,696		$ 270,748

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Dec. 15, 2016USD ($)	Nov. 02, 2016USD ($)	May 03, 2016USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2016USD ($)	Jun. 30, 2013USD ($)
Line of Credit Facility [Line Items]
Debt issuance costs written off				$ 563,000			$ 563,000
Senior notes, net					$ 225,839,000		226,653,000	$ 225,839,000
Gain on extinguishment of debt					9,080,000	$ 1,483,000		10,563,000
Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt issuance costs					4,481,000		3,667,000	4,481,000
Senior notes, net					225,839,000		$ 226,653,000	225,839,000
7% Senior Notes Originated June 11, 2013 [Member] | Senior Notes [Member]
Line of Credit Facility [Line Items]
Senior notes, net										$ 250,000,000
Stated interest rate							7.00%
Debt instrument payment of interest							Semi-annually on June 15 and December 15.
Semi-annual interest payment amount	$ 8,100,000
Proceeds from issuance of senior notes							$ 243,000,000
Repurchased senior notes face value					19,700,000			19,700,000
Repurchased price of senior notes								8,800,000
Gain on extinguishment of debt								10,600,000
Debt exchange to common stock, principal amount		$ 130,600,000
Future interest savings		$ 40,000,000
Senior Secured Credit Facility [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, borrowing base			$ 325,000,000				325,000,000		$ 450,000,000
Senior secured facility, maximum borrowing capacity							$ 1,000,000,000
Maturity period of senior secured credit facility							May 7, 2019
Annual commitment fee of unused borrowings							0.50%
Senior secured credit facility, interest rate description							Borrowings under the Credit Facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.50% to 2.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 2.50% to 3.50%. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available.
Senior secured credit facility					273,000,000		$ 273,000,000	273,000,000
Interest rate applicable of senior secured credit facility							3.30%
Unused letters of credit outstanding					300,000		$ 600,000	300,000
Production from liens covering the oil and gas properties							90.00%
Interest coverage ratio, through December 31, 2018			1.5
Interest coverage ratio, thereafter			2
Increase in applicable margin rates on borrowings			1.00%
Second lien indebtedness			$ 150,000,000
Cash and cash equivalents, minimum threshold to reduce outstanding borrowings under credit facility			35,000,000
Debt issuance costs written off			600,000
Debt issuance costs			$ 200,000		$ 2,252,000		$ 1,304,000	$ 2,252,000
Outstanding equity interests ownership percentage							50.00%
Senior Secured Credit Facility [Member] | Covenants Agreements One [Member]
Line of Credit Facility [Line Items]
Covenant description							 a consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to cash Interest Expense (as defined in the Credit Facility) as of the last day of any fiscal quarter of not less than 1.25 to 1.0 (or 1.0 to 1.0 following the issuance of second lien indebtedness) through December 31, 2017, a ratio of not less than 1.5 to 1.0 through December 31, 2018, and a ratio of not less than 2.0 to 1.0 thereafter, and  a consolidated modified current ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.
Senior Secured Credit Facility [Member] | Before Second Lien Indebtedness [Member]
Line of Credit Facility [Line Items]
Interest coverage ratio, through December 31, 2017			1.25
Senior Secured Credit Facility [Member] | Before Second Lien Indebtedness [Member] | Covenants Agreements One [Member]
Line of Credit Facility [Line Items]
Minimum current ratio							1.25
Senior Secured Credit Facility [Member] | After Second Lien Indebtedness [Member]
Line of Credit Facility [Line Items]
Interest coverage ratio, through December 31, 2017			1
Senior Secured Credit Facility [Member] | After Second Lien Indebtedness [Member] | Covenants Agreements One [Member]
Line of Credit Facility [Line Items]
Minimum current ratio							1
Senior Secured Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							1.50%
Senior Secured Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							2.50%
Senior Secured Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							2.50%
Senior Secured Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage							3.50%

Termination Costs - Additional

Termination Costs - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Restructuring Cost and Reserve [Line Items]
Severance expenses		$ 1,436
Current Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
Termination costs recorded in current liabilities			$ 1,400
Employee Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance expenses	$ 300
Employee Severance [Member] | General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Benefit recorded in share-based compensation expense	$ 300

Share-Based Compensation - Addi

Share-Based Compensation - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amendment effective date	Jun. 2, 2016
Share-based compensation expense	$ 6,300,000	$ 8,000,000	$ 8,200,000
Shares subject to stock options, granted	0	0	0
Shares subject to stock options, shares exercisable	38,525
Weighted average exercise price, outstanding	$ 12
Weighted average remaining contractual term, outstanding	10 months 6 days
Number of stock options exercised	0	0	0
Subsequent restricted share award	1,443,256
Current fiscal year employer matching contribution description	We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation
Contributions to employee benefit plan	$ 338,000	$ 404,000	$ 310,000
Primary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution, percentage	100.00%
Secondary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution, percentage	50.00%
Non-Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 214,000	$ 735,000	749,000
Forfeiture Benefit Adjustments Member [Member] | Executive Officers [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited stock awards			$ 1,100,000
Nonvested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares grant	1,318,229	1,278,329	992,919
Average grant date fair value	$ 2,500,000	$ 6,200,000	$ 14,400,000
Unrecognized compensation expense related to nonvested shares	$ 4,000,000
Nonvested outstanding weighted average remaining service period	2 years
Nonvested Shares [Member] | Executive Officers [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares grant	550,272	724,249	245,157
Additional share grant fair value	$ 300,000	$ 4,500,000	$ 4,500,000
Cash Settled Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share awards, subject to certain performance conditions	1,100,543
Fair market value of shares subject to performance conditions	$ 1,000,000
Service period	3 years
Cash Settled Performance Shares [Member] | General and Administrative Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1,300,000
Cash Settled Performance Shares [Member] | Current Liability [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, liability	600,000
Cash Settled Performance Shares [Member] | Non-Current Liability [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, liability	700,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair market value of shares subject to performance conditions	$ 2,900,000
Service period	3 years
Subsequent restricted share award	962,171
Total Shareholder Return Performance Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Subsequent restricted share award	481,085
2007 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
The maximum number of common stock	6,125,000

Share-Based Compensation - Summ

Share-Based Compensation - Summary of Status of Nonvested Shares (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Nonvested Shares, Beginning Balance	1,735,256	1,122,410	699,231
Nonvested Shares, Granted	1,318,229	1,278,329	992,919
Nonvested Shares, Vested	(992,461)	(419,222)	(400,429)
Nonvested Shares, Canceled	(107,960)	(246,261)	(169,311)
Nonvested Shares, Ending Balance	1,953,064	1,735,256	1,122,410
Weighted Average Grant-Date Fair Value, Nonvested, Beginning Balance	$ 8.60	$ 16.52	$ 23.70
Weighted Average Grant-Date Fair Value, Nonvested, Granted	1.90	4.87	14.48
Weighted Average Grant-Date Fair Value, Nonvested, Vested	7.03	15.26	20.18
Weighted Average Grant-Date Fair Value, Nonvested, Canceled	17.33	14.30	25.57
Weighted Average Grant-Date Fair Value, Nonvested, Ending Balance	$ 4.39	$ 8.60	$ 16.52

Income Taxes - Schedule of Prov

Income Taxes - Schedule of Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
Federal		$ (265)	$ (25)
Total current provision for income taxes		(265)	(25)
Deferred:
Federal	$ (24,957)	(91,716)	32,754
State	539	(1,424)	963
Total deferred provision for income taxes	$ (24,418)	$ (93,140)	$ 33,717

Income Taxes - Total Income Tax

Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Detail) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Statutory tax at 35%													$ (26,831)	$ (93,628)	$ 31,452
State taxes, net of federal impact													578	(1,463)	989
Share-based compensation tax shortfall													1,826	1,939	1,670
Permanent differences													11	26	37
Other differences													(2)	(1,035)	(456)
Valuation allowance														756
Total	$ (3,571)	$ (4,915)	$ (8,687)	$ (7,245)	$ (284)	$ (81,756)	$ (7,369)	$ (3,996)	$ 17,102	$ 12,756	$ 2,153	$ 1,681	$ (24,418)	$ (93,405)	$ 33,692

Income Taxes - Total Income T42

Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	Jan. 02, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Share-based compensation tax shortfall		$ 1,826	$ 1,939	$ 1,670
Net deferred tax assets and liabilities recorded as long-term liability		$ 5,600	$ 31,800
NOLs, limitations on use		A change in ownership of our common stock by more than 50% within a three-year period would result in a substantial portion of our NOLs being eliminated or becoming restricted, and we would need to reduce our deferred tax assets to reflect the restricted use of these NOLs when such an ownership change occurs. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change, multiplied by the federal long-term tax exempt rate for the month of the ownership change.
New Accounting Pronouncement, Early Adoption, Effect [Member]
Income Taxes [Line Items]
Increase in accumulated earnings and NOLs	$ 1,700

Income Taxes - Significant Comp

Income Taxes - Significant Components of Net Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 155,018	$ 88,230
Unrealized loss on commodity derivatives	1,732
Other	892	1,672
Total deferred tax assets	157,642	89,902
Difference in depreciation, depletion and capitalization methods — oil and gas properties	(162,501)	(118,534)
Unrealized gain on commodity derivatives		(2,391)
Total deferred tax liabilities	(162,501)	(120,925)
Valuation allowance	(756)	(756)
Net deferred tax liability	$ (5,615)	$ (31,779)

Income Taxes - Schedule of NOLs

Income Taxes - Schedule of NOLs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Operating Loss Carryforwards [Line Items]
Amounts	$ 442,904
Expiration Dates 2030 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 5,790
Expiration Dates	2,030
Expiration Dates 2031 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 19,686
Expiration Dates	2,031
Expiration Date 2032 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 54,714
Expiration Dates	2,032
Expiration Date 2033 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 78
Expiration Dates	2,033
Expiration Date 2034 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 56,505
Expiration Dates	2,034
Expiration Date 2035 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 116,482
Expiration Dates	2,035
Expiration Date 2036 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	$ 189,649
Expiration Dates	2,036

Derivative Instruments and Fa46

Derivative Instruments and Fair Value Measurements - Commodity Derivatives Volumes and Prices (Detail)	Mar. 09, 2017MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2016MMBTU$ / MMBTU
Natural Gas January 2017 - March 2017 Contract One [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		100,000
Contract Price		2.463
Natural Gas January 2017 - March 2017 Contract Two [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		300,000
Contract Price		2.45
Natural Gas January 2017 - March 2017 Contract Three [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Contract Price		3.287
Natural Gas January 2017 - December 2017 Contract [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		100,000
Natural Gas January 2017 - December 2017 Contract [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3
Natural Gas January 2017 - December 2017 Contract [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.65
Natural Gas April 2017 - December 2017 Contract One [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Natural Gas April 2017 - December 2017 Contract One [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		2.30
Natural Gas April 2017 - December 2017 Contract One [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		2.60
Natural Gas April 2017 - December 2017 Contract Two [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Natural Gas April 2017 - December 2017 Contract Two [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3
Natural Gas April 2017 - December 2017 Contract Two [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.44
Natural Gas April 2017 - December 2017 Contract Three [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU		200,000
Natural Gas April 2017 - December 2017 Contract Three [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3
Natural Gas April 2017 - December 2017 Contract Three [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price		3.50
Natural Gas January 2018 - December 2018 Contract One [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU	200,000
Contract Price	3.085
Natural Gas January 2018 - December 2018 Contract Two [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU	250,000
Contract Price	3.084
NGLs (C2 - Ethane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	1,050
Contract Price | $ / bbl	11.34
NGLs (C3 - Propane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	750
Contract Price | $ / bbl	27.916
NGLs (IC4 - Isobutane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	75
Contract Price | $ / bbl	36.7325
NGLs (NC4 - Butane) February 2017 - December 2017 Contract [Member] | Swap [Member] | Subsequent Event [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	250
Contract Price | $ / bbl	35.9205

Derivative Instruments and Fa47

Derivative Instruments and Fair Value Measurements - Summary of Fair Value of Open Commodity Derivatives (Detail) - Commodity Derivatives [Member] - Unrealized (Loss) Gain on Commodity Derivatives [Member] - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Derivatives not designated as hedging instruments, fair value of Liability derivative	$ (4,880)
Derivatives not designated as hedging instruments, fair value of assets derivative		$ 6,737

Derivative Instruments and Fa48

Derivative Instruments and Fair Value Measurements - Summary of Change in Fair Value of Commodity Derivatives (Detail) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives	$ 442	$ 781	$ 1,409	$ 3,500	$ 14,552	$ 12,755	$ 9,281	$ 15,901	$ 7,782	$ (764)	$ (3,320)	$ (1,339)	$ 6,132	$ 52,489	$ 2,359
Derivatives Not Designated as Hedging Instruments [Member]
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives													(5,484)	19,275	44,472
Derivatives Not Designated as Hedging Instruments [Member] | Unrealized (Loss) Gain on Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives													(11,616)	(33,214)	42,113
Derivatives Not Designated as Hedging Instruments [Member] | Realized Gain on Commodity Derivatives [Member]
Derivatives Fair Value [Line Items]
Total gain (loss) on commodity derivatives													$ 6,132	$ 52,489	$ 2,359

Derivative Instruments and Fa49

Derivative Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2015
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Impairment of oil and gas properties and equipment	$ 0	$ 220,197,000	$ 0
Proved oil and gas property fair value				$ 22,000,000
Proved Property Impairment [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Impairment of oil and gas properties and equipment	$ 0	$ 214,700,000

Derivative Instruments and Fa50

Derivative Instruments and Fair Value Measurements - Summary of Financial Instruments Not Recorded at Fair Value (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Senior notes, net	$ 226,653	$ 225,839
Senior Notes, Fair Value	$ 206,286

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Jan. 31, 2017USD ($)ft²	Dec. 31, 2017USD ($)ExecutiveOfficer	Dec. 31, 2016USD ($)ExecutiveOfficer	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Other Commitments [Line Items]
Number of executive officers contained automatic renewal provisions | ExecutiveOfficer			4
Contractual settlement			$ 1,400,000
Non-Cancelable operating lease expiration date			2,021
Non-Cancelable lease agreement for office space, expiration date			Mar. 31, 2020
Rent expense under lease arrangements			$ 1,025,000	$ 1,002,000	$ 717,000
Legal settlement received from a service provider			1,100,000
Subsequent Event [Member]
Other Commitments [Line Items]
Non-Cancelable lease agreement for office space, expiration date	Sep. 30, 2021
Reduction in aggregate leased space | ft²	5,500
Reduction in contractual obligations during next three years	$ 400,000
Increase in total contractual obligations	$ 900,000
Scenario, Forecast [Member]
Other Commitments [Line Items]
Number of executive officers contained automatic renewal provisions | ExecutiveOfficer		2
Employment Agreements [Member]
Other Commitments [Line Items]
Commitment under contracts			$ 5,700,000
Employment Agreements [Member] | Scenario, Forecast [Member]
Other Commitments [Line Items]
Commitment under contracts		$ 600,000

Commitments and Contingencies52

Commitments and Contingencies - Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements (Detail) $ in Thousands	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 989
2,018	979
2,019	980
2,020	248
2,021	2
Total	$ 3,198

Oil and Gas Producing Activit53

Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Unproved properties	$ 17	$ 653	$ 4,578
Exploration costs	3,923	4,439	3,831
Development costs	15,884	146,237	382,995
Total costs incurred	$ 19,824	$ 151,329	$ 391,404

Oil and Gas Producing Activit54

Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Parenthetical) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$ 15,884	$ 146,237	$ 382,995
Non-cash Asset Retirement Obligations [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$ 36,000	$ 151,000	$ 898,000

Oil and Gas Producing Activit55

Oil and Gas Producing Activities - Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Revenues	$ 90,302,000	$ 131,336,000	$ 258,529,000
Production costs	(27,467,000)	(40,057,000)	(48,635,000)
Exploration expense	(3,923,000)	(4,439,000)	(3,831,000)
Depletion	(79,044,000)	(109,319,000)	(106,802,000)
Impairment of oil and gas properties	0	(220,197,000)	0
Income tax benefit (expense)	7,144,000	86,120,000	(35,387,000)
Results of operations	$ (12,988,000)	$ (156,556,000)	$ 63,874,000

Disclosures About Oil and Gas56

Disclosures About Oil and Gas Producing Activities - Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation (Detail) - Reserve Estimate [Member]	12 Months Ended
	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf
Oil (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	42.69	50.16	94.56
NGLs (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	14.12	15.13	31.50
Natural Gas (MMcf) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices | $ / Mcf	2.47	2.64	4.55

Disclosures About Oil and Gas57

Disclosures About Oil and Gas Producing Activities - Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf
Reserve Quantities [Line Items]
Production | MMcf	(1,330)	(1,530)	(1,390)
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | MBoe	166,646	146,248	114,661
Extensions and discoveries | MBoe	16,651	34,895	43,247
Production | MBoe	(4,759)	(5,787)	(5,281)
Revisions to previous estimates | MBoe	(22,161)	(8,710)	(6,379)
Proved Developed and Proved Undeveloped Reserves, Ending Balance | MBoe	156,377	166,646	146,248
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	54,496	55,338	46,067
Extensions and discoveries	6,529	11,054	19,347
Production	(1,275)	(1,882)	(2,024)
Revisions to previous estimates	(9,719)	(10,014)	(8,052)
Proved Developed and Proved Undeveloped Reserves, Ending Balance	50,031	54,496	55,338
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	49,486	40,907	32,593
Extensions and discoveries	4,564	10,630	10,658
Production	(1,529)	(1,694)	(1,461)
Revisions to previous estimates	(4,887)	(357)	(883)
Proved Developed and Proved Undeveloped Reserves, Ending Balance	47,634	49,486	40,907
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | MMcf	375,988	300,020	216,002
Extensions and discoveries | MMcf	33,347	79,268	79,454
Production | MMcf	(11,734)	(13,262)	(10,773)
Revisions to previous estimates | MMcf	(45,324)	9,962	15,337
Proved Developed and Proved Undeveloped Reserves, Ending Balance | MMcf	352,277	375,988	300,020

Disclosures About Oil and Gas58

Disclosures About Oil and Gas Producing Activities - Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf
Reserve Quantities [Line Items]
Field fuel | MMcf	1,330	1,530	1,390
Proved Developed Reserves | MBoe	58,875	61,856	60,220	45,189
Proved Undeveloped Reserves | MBoe	97,502	104,790	86,028	69,472
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Field fuel	1,275	1,882	2,024
Proved Developed Oil Reserves	13,466	15,667	17,978	13,646
Proved Undeveloped Oil Reserves	36,565	38,829	37,360	32,421
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Field fuel	1,529	1,694	1,461
Proved Developed Oil Reserves	20,375	20,414	19,082	14,919
Proved Undeveloped Oil Reserves	27,259	29,072	21,825	17,674
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Field fuel | MMcf	11,734	13,262	10,773
Proved Developed Oil Reserves | MMcf	150,208	154,652	138,961	99,742
Proved Undeveloped Oil Reserves | MMcf	202,069	221,335	161,059	116,260

Disclosures About Oil and Gas59

Disclosures About Oil and Gas Producing Activities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016MBoeMMcf	Dec. 31, 2015MBoeMMcf	Dec. 31, 2014MBoeMMcf
Reserve Quantities [Line Items]
Extensions and discoveries	16,651	34,895	43,247
Economic revisions	22,400	11,900	9,300
Production	4,800	5,800	5,300
Field fuel | MMcf	1,330	1,530	1,390
Significant changes in reserves	Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices.	Extensions and discoveries for 2015 were 34.9 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2015, we reclassified 11.9 MMBoe of proved reserves to unproved reserves. The reserves reclassified are attributable to horizontal and vertical well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 13 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 9.8 MMBoe due to lower commodity prices.	Extensions and discoveries for 2014 were 43.2 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2014, we reclassified 9.3 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified included 5.8 MMBoe attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking, and 3.5 MMBoe attributable to horizontal Wolfcamp locations that are no longer included in our proved development plan. Revisions included an increase of 6.3 MMBoe attributable to updated well performance and an increase of 0.7 MMBoe due to pricing, offset by a decrease of 4.1 MMBoe resulting from updated technical parameters and costs.
Period for reclassification of proved reserves to unproved reserves	5 years	5 years
Increased revisions due to cost reduction, updated well Performance and technical parameters	2,100	13,000
Decreased revisions due to lower commodity prices	1,900	9,800
Increased revisions	(22,161)	(8,710)	(6,379)
Increased revision due to pricing			700
Southeast Project Pangea [Member]
Reserve Quantities [Line Items]
Economic revisions			5,800
Decreased revisions			4,100
Wolfcamp Shale Oil Resources [Member]
Reserve Quantities [Line Items]
Economic revisions			3,500
Increased revisions			6,300

Disclosures About Oil and Gas60

Disclosures About Oil and Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash flows	$ 3,319,551	$ 4,097,568	$ 7,430,368
Future production costs	(1,054,211)	(1,237,888)	(1,704,333)
Future development costs	(829,926)	(934,814)	(1,247,446)
Future income tax expense	(132,834)	(307,374)	(1,267,025)
Future net cash flows	1,302,580	1,617,492	3,211,564
10% annual discount for estimated timing of cash flows	(1,004,825)	(1,157,097)	(2,155,749)
Standardized measure of discounted future net cash flows	$ 297,755	$ 460,395	$ 1,055,815	$ 676,277

Disclosures About Oil and Gas61

Disclosures About Oil and Gas Producing Activities - Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Standardized measure of discounted future net cash flows, Beginning balance	$ 460,395	$ 1,055,815	$ 676,277
Net change in sales and transfer prices and in production (lifting) costs related to future production	(191,841)	(1,405,864)	(59,920)
Changes in estimated future development costs	17,405	231,900	(388,772)
Sales and transfers of oil and gas produced during the period	(62,835)	(91,278)	(209,893)
Net change due to extensions, discoveries and improved recovery	13,988	156,783	534,231
Net change due to revisions in quantity estimates	(25,236)	(59,305)	(78,801)
Previously estimated development costs incurred during the period	15,884	146,237	382,995
Accretion of discount	46,040	105,582	113,188
Other	(9,500)	6,915	(11,897)
Net change in income taxes	33,455	313,610	98,407
Standardized Measure of discounted future net cash flows	$ 297,755	$ 460,395	$ 1,055,815

Supplementary Data - Selected Q

Supplementary Data - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Net revenues	$ 26,505	$ 23,749	$ 22,433	$ 17,615	$ 25,492	$ 33,941	$ 38,605	$ 33,298	$ 55,070	$ 68,124	$ 73,408	$ 61,927	$ 90,302	$ 131,336	$ 258,529
Net operating expenses	(33,564)	(32,201)	(34,534)	(34,869)	(38,671)	(272,462)	(46,970)	(45,686)	(50,136)	(45,525)	(50,812)	(44,899)	(135,168)	(403,789)	(191,372)
Interest expense, net	(7,086)	(7,067)	(6,808)	(6,298)	(6,436)	(6,465)	(6,243)	(5,922)	(5,715)	(5,442)	(5,357)	(5,137)	(27,259)	(25,066)	(21,651)
Gain on debt extinguishment					9,080	1,483								10,563
Write-off of debt issuance costs			(563)										(563)
Equity in earnings (losses) of investee									5		(186)				(181)
Realized gain on commodity derivatives	442	781	1,409	3,500	14,552	12,755	9,281	15,901	7,782	(764)	(3,320)	(1,339)	6,132	52,489	2,359
Unrealized (loss) gain on commodity derivatives	(3,343)	760	(8,076)	(957)	(10,285)	296	(13,904)	(9,321)	36,907	18,810	(7,678)	(5,926)	(11,616)	(33,214)	42,113
Other income (expense)		(10)	1,417	104	225	(91)	12	26	176		(109)		1,511	172	67
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION	(17,046)	(13,988)	(24,722)	(20,905)	(6,043)	(230,543)	(19,219)	(11,704)	44,089	35,203	5,946	4,626	(76,661)	(267,509)	89,864
Income tax provision (benefit)	(3,571)	(4,915)	(8,687)	(7,245)	(284)	(81,756)	(7,369)	(3,996)	17,102	12,756	2,153	1,681	(24,418)	(93,405)	33,692
NET (LOSS) INCOME	$ (13,475)	$ (9,073)	$ (16,035)	$ (13,660)	$ (5,759)	$ (148,787)	$ (11,850)	$ (7,708)	$ 26,987	$ 22,447	$ 3,793	$ 2,945	$ (52,243)	$ (174,104)	$ 56,172
Basic net income (loss) applicable to common stockholders per common share	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.43
Diluted net income (loss) applicable to common stockholders per common share	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ 0.68	$ 0.57	$ 0.10	$ 0.08	$ (1.26)	$ (4.30)	$ 1.42