Approach Resources (AREXQ) 10-K 9 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 02, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
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		94,333,181
Entity Public Float			$ 135.2

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 21	$ 21
Accounts receivable:
Joint interest owners	117	92
Oil, NGLs and gas sales	9,678	9,547
Derivative assets	1,398
Prepaid expenses and other current assets	5,486	2,834
Total current assets	16,700	12,494
PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting	1,930,577	1,869,774
Furniture, fixtures and equipment	5,658	5,644
Total oil and gas properties and equipment	1,936,235	1,875,418
Less accumulated depletion, depreciation and amortization	(853,359)	(783,357)
Net oil and gas properties and equipment	1,082,876	1,092,061
Total assets	1,099,576	1,104,555
CURRENT LIABILITIES:
Accounts payable	9,450	9,482
Oil, NGLs and gas sales payable	5,363	4,190
Derivative liabilities	2,181	4,880
Accrued liabilities	8,073	7,817
Total current liabilities	25,067	26,369
NON-CURRENT LIABILITIES:
Senior secured credit facility, net	289,275	271,696
Senior notes, net	84,185	226,653
Deferred income taxes	82,102	5,615
Asset retirement obligations	11,065	10,607
Other non-current liabilities	466	663
Total liabilities	492,160	541,603
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, 180,000,000 and 90,000,000 shares authorized, 94,533,246 and 41,764,770 issued and outstanding, respectively	945	418
Additional paid-in capital	742,391	586,095
Accumulated deficit	(135,920)	(23,561)
Total stockholders’ equity	607,416	562,952
Total liabilities and stockholders’ equity	$ 1,099,576	$ 1,104,555

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
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	180,000,000	90,000,000
Common stock, issued	94,533,246	41,764,770
Common stock, outstanding	94,533,246	41,764,770

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES:
Oil, NGLs and gas sales		$ 105,349,000	$ 90,302,000	$ 131,336,000
EXPENSES:
Lease operating		17,902,000	19,250,000	28,972,000
Production and ad valorem taxes		8,644,000	8,217,000	11,085,000
Exploration		3,657,000	3,923,000	4,439,000
General and administrative	[1]	24,333,000	24,734,000	28,341,000
Termination costs				1,436,000
Impairment of oil and gas properties		0	0	220,197,000
Depletion, depreciation and amortization		70,521,000	79,044,000	109,319,000
Total expenses		125,057,000	135,168,000	403,789,000
OPERATING LOSS		(19,708,000)	(44,866,000)	(272,453,000)
OTHER:
Interest expense, net		(21,053,000)	(27,259,000)	(25,066,000)
Gain on debt extinguishment		5,053,000		10,563,000
Write-off of debt issuance costs			(563,000)
Commodity derivative (loss) gain		(262,000)	(5,484,000)	19,275,000
Other income		32,000	1,511,000	172,000
LOSS BEFORE INCOME TAX PROVISON (BENEFIT)		(35,938,000)	(76,661,000)	(267,509,000)
INCOME TAX PROVISON (BENEFIT):
Current		(66,000)		(265,000)
Deferred		76,487,000	(24,418,000)	(93,140,000)
NET LOSS		$ (112,359,000)	$ (52,243,000)	$ (174,104,000)
LOSS PER SHARE:
Basic		$ (1.35)	$ (1.26)	$ (4.30)
Diluted		$ (1.35)	$ (1.26)	$ (4.30)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		83,404,104	41,488,206	40,464,283
Diluted		83,404,104	41,488,206	40,464,283
[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, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Includes non-cash share-based compensation expense	$ 4,656	$ 6,279	$ 7,954

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, 2014	$ 774,327	$ 399	$ 572,888	$ 201,040
Beginning 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
Issuance of common shares to directors for compensation, value	449	$ 1	448
Issuance of common shares to directors for compensation, shares		179,255
Restricted stock issuance, net of cancellations, value		$ 20	(20)
Restricted stock issuance, net of cancellations, shares		2,074,539
Share-based compensation expense	4,207		4,207
Surrender of restricted shares for payment of income taxes, value	(651)	$ (2)	(649)
Surrender of restricted shares for payment of income taxes, shares		(234,049)
Issuance of common shares in exchange for senior notes, value	134,958	$ 432	134,526
Issuance of common shares in exchange for senior notes, shares		43,175,328
Issuance of common shares for acquisition, value	17,860	$ 76	17,784
Issuance of common shares for acquisition, shares		7,573,403
Net (loss) income	(112,359)			(112,359)
Ending balance, value at Dec. 31, 2017	$ 607,416	$ 945	$ 742,391	$ (135,920)
Ending balance, shares at Dec. 31, 2017		94,533,246

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES:
Net loss	$ (112,359,000)	$ (52,243,000)	$ (174,104,000)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	70,521,000	79,044,000	109,319,000
Impairment of oil and gas properties	0	0	220,197,000
Amortization of debt issuance costs	866,000	1,396,000	1,561,000
Gain on debt extinguishment	(5,053,000)		(10,563,000)
Write-off of debt issuance costs		563,000
Commodity derivative loss (gain)	262,000	5,484,000	(19,275,000)
Settlements of commodity derivatives	(4,359,000)	6,132,000	52,489,000
Exploration expense	3,522,000	3,753,000	1,836,000
Share-based compensation expense	4,656,000	6,279,000	7,954,000
Deferred income tax (benefit) expense	76,487,000	(24,418,000)	(93,140,000)
Other non-cash items	(32,000)	(92,000)	(172,000)
Changes in operating assets and liabilities:
Accounts receivable	400,000	2,250,000	7,878,000
Prepaid expenses and other current assets	83,000	534,000	(325,000)
Accounts payable	907,000	358,000	964,000
Oil, NGLs and gas sales payable	919,000	(55,000)	(4,291,000)
Accrued liabilities	634,000	(2,904,000)	2,388,000
Cash provided by operating activities	37,454,000	26,081,000	102,716,000
INVESTING ACTIVITIES:
Additions to oil and gas properties	(47,051,000)	(19,788,000)	(151,178,000)
Additions to furniture, fixtures and equipment, net	(14,000)	(16,000)	(67,000)
Change in working capital related to investing activities	(5,344,000)	(4,086,000)	(66,102,000)
Cash used in investing activities	(52,409,000)	(23,890,000)	(217,347,000)
FINANCING ACTIVITIES:
Borrowings under credit facility	111,250,000	50,100,000	272,000,000
Repayment of amounts outstanding under credit facility	(93,250,000)	(50,100,000)	(149,000,000)
Extinguishment of senior notes			(8,722,000)
Tax withholdings related to restricted stock	(650,000)	(797,000)	(210,000)
Equity issuance costs	(2,780,000)
Debt issuance costs	(977,000)	(197,000)
Change in working capital related to financing activities	1,362,000	(1,776,000)	731,000
Cash (used in) provided by financing activities	14,955,000	(2,770,000)	114,799,000
CHANGE IN CASH AND CASH EQUIVALENTS		(579,000)	168,000
CASH AND CASH EQUIVALENTS , beginning of year	21,000	600,000	432,000
CASH AND CASH EQUIVALENTS , end of year	21,000	21,000	600,000
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	20,584,000	25,972,000	23,634,000
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
Asset retirement obligations capitalized	$ 39,000	$ 36,000	$ 151,000

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Mineral interests in properties: Unproved leasehold costs $ 28,737 $ 33,596 Proved leasehold costs 60,077 44,643 Wells and related equipment and facilities 1,819,836 1,774,314 Support equipment 8,459 8,002 Uncompleted wells, equipment and facilities 13,468 9,219 Total costs 1,930,577 1,869,774 Less accumulated depreciation, depletion and amortization (850,301 ) (780,412 ) Net capitalized costs $ 1,080,276 $ 1,089,362 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, 2017 or 2016. 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, 2017, 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 $70.3 million, $78.7 million and $108.8 million for the years ended December 31, 2017, 2016 and 2015, 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, 2017 and 2016. 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 $237,000, $343,000 and $563,000 for the years ended December 31, 2017, 2016 and 2015, 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, 2017 and 2016. 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, 2017 or 2016. 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 2014 and forward and Texas income and margin tax returns for tax years 2014 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 currently have a valuation allowance of $0.5 million on our deferred tax assets, after accounting for the change in the corporate federal income tax rate under the Tax Cuts and Jobs Act. Derivative Activity We record our open derivative instruments at fair value on our consolidated balance sheets as either derivative assets or liabilities. Cash settlements and changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur on our consolidated statements of operations under the caption entitled “commodity derivative (loss) gain.” We have not historically designated our derivative instruments as cash-flow hedges; however we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Derivative assets and derivative liabilities, 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. Prepaid Expenses and Other Assets In April 2017, we entered into an agreement that secured pricing and availability of a dedicated hydraulic fracturing services crew. Under this agreement, we made a prepayment of $5 million, to be used as we completed wells. We have used $0.7 million of this prepayment related to hydraulic fracturing services provided during the first year of the agreement. As of December 31, 2017, we maintained an unused prepaid balance of $4.3 million in prepaid expenses and other current assets on our consolidated balance sheets related to this agreement. After December 31, 2017, we used an additional $0.5 million of this prepayment and $3.8 million of the unused prepaid balance was refunded to us. Accrued Liabilities The following is a summary of our accrued liabilities at December 31, 2017 and 2016 (in thousands): 2017 2016 Capital expenditures accrual $ 1,522 $ 1,067 Operating expenses and other 6,551 6,750 Total $ 8,073 $ 7,817 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, 2017, 2016 and 2015. 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. Additionally, we recognize forfeitures of share-based compensation as they occur. 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, 2017 2016 2015 Income (numerator): Net (loss) income — basic $ (112,359 ) $ (52,243 ) $ (174,104 ) Weighted average shares (denominator): Weighted average shares — basic 83,404,104 41,488,206 40,464,283 Dilution effect of share-based compensation, treasury method (1) — — — Weighted average shares — diluted 83,404,104 41,488,206 40,464,283 Net (loss) income per share: Basic $ (1.35 ) $ (1.26 ) $ (4.30 ) Diluted $ (1.35 ) $ (1.26 ) $ (4.30 ) (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. No options were outstanding as of December 31, 2017, as they had expired. 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, 2017 or 2016. 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, 2017, sales to American Midstream, LP (“AMID”), a successor to JP Energy Development, LP (“JP Energy”), and DCP Midstream, LP (“DCP”) accounted for approximately 52% and 47%, respectively, of our total sales. As of December 31, 2017, we had dedicated the majority of our oil production from Project Pangea through September 2022 to AMID. In addition, as of December 31, 2017, we had contracted to sell the majority of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2016, sales to DCP and JP Energy accounted for approximately 46% and 54%, respectively of our total sales. For the year ended December 31, 2015, sales to DCP and JP Energy accounted for approximately 36% and 63%, 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 (the “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 completed our detailed review of our individual purchaser contracts and we have evaluated the impact of this accounting standards update on our consolidated financial statements. We adopted this standard using the modified retrospective method of adoption on January 1, 2018. Adoption of this standard did not have a significant impact on our consolidated statements of operations or cash flows. We 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. Currently, the Company is evaluating the standard’s applicability to our various contractual arrangements. We believe that the adoption this standard will result in recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still 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, 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. In August 2017, FASB issued an accounting standards update for “Derivatives and Hedging,” impact our consolidated statements of operations or cash flows. F-1

Equity Exchange Transactions

Equity Exchange Transactions	12 Months Ended
	Dec. 31, 2017
Equity Exchange Transactions [Abstract]
Equity Exchange Transactions	2. Equity Exchange Transactions Debt exchange On November 2, 2016, we entered into an exchange agreement with Wilks Brothers, LLC and SDW Investments, LLC (collectively, “Wilks”), the largest holder of our 7% Senior Notes due 2021 (the “Senior Notes”), to exchange $130,552,000 principal amount of our Senior Notes for 39,165,600 newly issued shares of common stock, par value $0.01 per share (the “Initial Exchange”). On January 26, 2017, our stockholders approved the Exchange Transactions (defined below) 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 Wilks. 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. On March 22, 2017, we exchanged an additional $14,528,000 principal amount of outstanding Senior Notes for 4,009,728 shares of our common stock (the “Follow-On Exchange”). The Initial Exchange and the Follow-On Exchange (together, the “Exchange Transactions”) reduced the principal amount of outstanding Senior Notes by $145.1 million and reduced interest payments by $44.3 million over the remaining term of the Senior Notes. The Exchange Transactions were accounted for as a debt extinguishment. A gain of $5.1 million was recognized on the Exchange Transactions for the difference between the fair market value of the shares issued, a Level 1 fair value measurement, and the net carrying value of the Senior Notes exchanged. We incurred equity issuance costs of $2.8 million related to the Exchange Transactions, which were recorded as a reduction to additional paid-in capital. The Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the usage of our pre-change net operating losses (“NOLs”) in the future. Accordingly, we reduced our NOL deferred tax assets by $139.1 million. Acquisition On November 1, 2017, we entered into a definitive agreement to acquire producing properties directly adjacent to our acreage in the Permian Basin (the “Bolt-On Acquisition”). The Bolt-On Acquisition closed on November 20, 2017, and we issued 7,573,403 newly issued shares of common stock, par value $0.01 per share, with an effective date of September 1, 2017. The purchase price is subject to customary post-closing adjustments, and is expected to be finalized in the first quarter of 2018. Any adjustments to the purchase price are expected to be settled in The Acquisition was accounted for using the acquisition method under ASC Topic 805, “ Business Combinations ,” which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date. The results of operations attributable to the Bolt-On Acquisition are included in our consolidated statements of operations beginning on November 20, 2017. We recognized revenue of $0.5 million from these assets from November 20, 2017 to December 31, 2017. In connection with the Bolt-On Acquisition, we incurred $0.1 million of acquisition-related costs which were expensed as incurred and are included in general and administrative expenses on our consolidated statements of operations. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed, pursuant to the Bolt-On The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed as a result of the Bolt-On Acquisition (in thousands): Accounts receivable $ 558 Proved leasehold costs 13,865 Lease and well equipment 3,466 Total assets acquired 17,889 Accounts payable (106 ) Oil, NGLs and gas sales payable (255 ) Accrued liabilities (25 ) Asset retirement obligations (71 ) Total liabilities assumed (457 ) Estimated fair value of net assets acquired $ 17,432 We estimated the fair value of oil and gas properties and equipment and asset retirement obligations as of November 20, 2017, using a discounted cash flow model, which is a non-recurring Level 3 fair value measurement. Significant inputs to the valuation of natural gas and oil properties 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) future oil and gas reserves to be recovered and the timing thereof, and (v) discount rates.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	3. Long-Term Debt The following table provides a summary of our long-term debt at December 31, 2017, and December 31, 2016 (in thousands). December 31, 2017 December 31, 2016 Senior secured credit facility: Outstanding borrowings $ 291,000 $ 273,000 Debt issuance costs (1,725 ) (1,304 ) Senior secured credit facility, net 289,275 271,696 Senior notes: Principal 85,240 230,320 Debt issuance costs (1,055 ) (3,667 ) Senior notes, net 84,185 226,653 Total long-term debt $ 373,460 $ 498,349 Senior Secured Credit Facility At December 31, 2017, 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, 2020. 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 2% to 3%, or the sum of the LIBOR rate plus an applicable margin ranging from 3% to 4%. 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 $291 million of outstanding borrowings under the Credit Facility at December 31, 2017, compared to $273 million of outstanding borrowings under the Credit Facility at December 31, 2016. The weighted average interest rate applicable to borrowings under the Credit Facility in 2017 was 4.5%. We also had outstanding unused letters of credit under our Credit Facility totaling $0.3 million at December 31, 2017, compared to $0.6 million at December 31, 2016, 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 95% of the total value of all oil and gas properties of the Company and its subsidiaries. On December 21, 2017, we entered into a fourth amendment to the Credit Facility. The fourth amendment, among other things, (a) extended the maturity date of the Credit Facility from May 7, 2019, to May 7, 2020, (b) increased the applicable margin rates on borrowings by 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) increased the applicable margin rates on borrowings by 100 basis points, (c) permits the Company to issue up to $150 million of second lien indebtedness, subject to various conditions and limitations, (d) permits the Company to repurchase outstanding debt with proceeds of certain asset sales, equity issuances or second lien indebtedness, and (e) 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 three principal financial covenants: • a consolidated interest coverage ratio covenant that requires us to maintain a ratio of (i) consolidated EBITDAX for the period of four fiscal quarters then ending to (ii) Cash Interest Expense for such period as of the last day of any fiscal quarter of not less than 1.5 to 1.0 through December 31, 2017, a ratio of not less than 1.75 to 1.0 through December 31, 2018, a ratio of not less than 2.25 to 1.0 through December 31, 2019, and 2.5 to 1.0 thereafter. EBITDAX is defined as consolidated net (loss) income plus (i) interest expense, net, (ii) income tax provision (benefit), (iii) depreciation, depletion, amortization, (iv) exploration expenses and (v) other noncash loss or expense (including share-based compensation and the change in fair value of any commodity derivatives), less noncash income. Cash Interest Expense is calculated as interest expense, net less amortization of debt issuance costs. At December 31, 2017, our consolidated interest coverage ratio was 2.7 to 1.0; • a consolidated modified current ratio covenant 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 consolidated modified current ratio is defined as the ratio of (i) current assets plus funds available under our revolving credit facility, less the current derivative asset, to (ii) current liabilities less the current derivative liability. At December 31, 2017, our consolidated modified current ratio was 2.1 to 1.0; and • a consolidated total leverage ratio covenant that imposes a maximum permitted ratio of (i) Total Debt to (ii) EBITDAX for the period of four fiscal quarters then ending of not more than 5.0 to 1.0, as of the last day of any fiscal quarter from March 31, 2019, through June 30, 2019, thereafter not more than 4.75 to 1.0 as of the last day of any fiscal quarter through December 31, 2019, and (iii) not more than 4.0 to 1.0 as of the last day of any fiscal quarter thereafter. Total Debt is defined as the face or principal amount of debt. Our leverage ratio is currently above the level that will be required as of March 31, 2019. 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, 2017, we made a semi-annual interest payment of $3 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, 2017, we completed t he Exchange Transactions which reduced the outstanding principal balance of our Senior Notes by $145.1 million and reduced future interest payments by $44.3 million over the remaining term of the Senior Notes. 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. Wilks, a related party, purchased a portion of our outstanding Senior Notes in the open market subsequent to the Exchange Transactions. The Company believes that Wilks held approximately $43 million of our outstanding Senior Notes as of December 31, 2017. The Senior Notes held by Wilks are included in Senior Notes, net on our consolidated balance sheets. Our interest expense includes interest attributable to any Senior Notes held by Wilks on our consolidated statements of operations. As of December 31, 2017, we recorded a current liability $0.1 million of accrued interest attributable to the Senior Notes held by Wilks. 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 on January 27, 2017, 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, 2017, 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, 2017
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, 2017, there was no remaining liability related to termination costs 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, 2017
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. The maximum number of shares of common stock available for the grant of awards under the 2007 Plan 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 $4.7 million, $6.3 million and $8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Such amounts represent the estimated fair value of stock awards for which the requisite service period elapsed during those periods. Share-based compensation expense for the years ended December 31, 2017, 2016 and 2015, included $449,000, $214,000 and $735,000, respectively, related to grants to non-employee directors. Stock Options There were no stock option grants during the years ended December 31, 2017, 2016 and 2015. During the year ended December 31, 2017, 38,525 options expired, and no options were outstanding as of December 31, 2017. There were no options exercised during the years ended December 31, 2017, 2016 and 2015. Nonvested Shares Share grants totaling 2,343,522 shares, 1,318,229 shares and 1,278,329 shares with an approximate aggregate fair market value of $5.6 million, $2.5 million and $6.2 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, 2017, 2016 and 2015, respectively. Included in the share grants for 2017, 2016 and 2015, are 1,492,652 shares, 550,272 shares and 724,249 shares, respectively, awarded to our executive officers. The aggregate fair market value of these shares on the grant date was $3.6 million, $0.3 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, 2017, 2016 and 2015, is presented below: Shares Weighted Average Grant-Date Fair Value Nonvested at January 1, 2015 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 Granted 2,343,522 2.39 Vested (902,197 ) 6.73 Canceled (89,728 ) 5.17 Nonvested at December 31, 2017 3,304,661 $ 2.21 As of December 31, 2017, 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 two 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 of the vested portion of the award, at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations. For the years ended December 31, 2017, and December 31, 2016, we recognized $0.8 million and $1.3 million in expense related to the cash-settled performance awards, respectively. As of December 31, 2017, we recorded a current liability of $1.6 million and a non-current liability of $0.5 million on our consolidated balance sheet related to these awards. Subsequent Restricted Share Award Subsequent to December 31, 2017, 774,590 cash settled performance awards, subject to certain performance conditions, and 387,295 restricted shares, subject to three-year total shareholder return (“TSR”) conditions, assuming maximum TSR, were granted to our executive officers. The aggregate fair market value of the cash settled performance awards and TSR restricted shares on the date of grant was approximately $2.4 million and $0.8 million, respectively, 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 $333,000, $338,000 and $404,000 during the years ended December 31, 2017, 2016 and 2015, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	6. Income Taxes Our provision for income taxes comprised the following (in thousands): Years Ended December 31, 2017 2016 2015 Current: Federal $ (66 ) $ — $ (265 ) State — — — Total current provision for income taxes $ (66 ) $ — $ (265 ) Deferred: Federal $ 75,341 $ (24,957 ) $ (91,716 ) State 1,146 539 (1,424 ) Total deferred provision for income taxes $ 76,487 $ (24,418 ) $ (93,140 ) 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, 2017 2016 2015 Statutory tax at 35% $ (12,578 ) $ (26,831 ) $ (93,628 ) State taxes, net of federal impact 528 578 (1,463 ) Share-based compensation tax shortfall 1,279 1,826 1,939 Permanent differences 11 11 26 Other differences 30 (2 ) (1,035 ) Change in federal tax rate (51,939 ) — — Write-off of deferred tax assets 139,090 — 756 Total $ 76,421 $ (24,418 ) $ (93,405 ) In 2017, t he Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the future use of our pre-change net operating losses (“NOLs”). Accordingly, we reduced our NOL deferred tax assets by $139.1 million. On December 22, 2017, the Tax Cuts and Jobs Act was enacted which, among other things, lowered the U.S. Federal income tax rate applicable to corporations from 35% to 21% and repealed the corporate alternative minimum tax. We recorded a net tax benefit of $51.9 million to reflect the impact of the Tax Cuts and Jobs Act as of December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. In 2017, 2016 and 2015, the Company recorded a tax shortfall related to share-based compensation of $1.3 million, $1.8 million and $1.9 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 recognized an increase in accumulated earnings and our NOLs in 2016 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 $82.1 million and $5.6 million at December 31, 2017 and 2016, respectively. Significant components of net deferred tax assets and liabilities are (in thousands): Years Ended December 31, 2017 2016 Deferred tax assets: Net operating loss carryforwards $ 39,991 $ 155,018 Derivative liabilities 471 1,732 Other 533 892 Total deferred tax assets 40,995 157,642 Deferred tax liabilities: Difference in depreciation, depletion and capitalization methods — oil and gas properties (122,335 ) (162,501 ) Derivative assets (302 ) — Total deferred tax liabilities (122,637 ) (162,501 ) Valuation allowance (460 ) (756 ) Net deferred tax liability $ (82,102 ) $ (5,615 ) T he Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the future use of our pre-change NOLs. Accordingly, we reduced our NOL deferred tax assets by $139.1 million in the year ended December 31, 2017. As of December 31, 2017, we

Derivative Instruments and Fair

Derivative Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Fair Value Measurements	7. Derivative Instruments and Fair Value Measurements At December 31, 2017, we had the following commodity derivatives positions outstanding: Commodity and Period Contract Type Volume Transacted Contract Price Crude Oil January 2018 — December 2018 Swap 300 Bbls/day $50.00/Bbl January 2018 — March 2018 Collar 1,000 Bbls/day $50.00/Bbl - $55.05/Bbl January 2018 — June 2018 Collar 500 Bbls/day $55.00/Bbl - $60.00/Bbl 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 (C3 - Propane) January 2018 — March 2018 Swap 450 Bbls/day $30.24/Bbl NGLs (IC4 - Isobutane) January 2018 — March 2018 Swap 50 Bbls/day $36.12/Bbl NGLs (NC4 - Butane) January 2018 — March 2018 Swap 150 Bbls/day $35.70/Bbl After December 31, 2017, we entered into the following commodity derivative positions: Commodity and Period Contract Type Volume Transacted Contract Price Crude Oil January 2018 — September 2018 Swap 700 Bbls/day $60.50/Bbl April 2018 — September 2018 Swap 800 Bbls/day $60.50/Bbl NGLs (C2 - Ethane) February 2018 — December 2018 Swap 1,000 Bbls/day $11.424/Bbl NGLs (C3 - Propane) February 2018 — December 2018 Swap 600 Bbls/day $32.991/Bbl NGLs (IC4 - Isobutane) February 2018 — December 2018 Swap 50 Bbls/day $38.262/Bbl NGLs (NC4 - Butane) February 2018 — December 2018 Swap 200 Bbls/day $38.22/Bbl NGLs (C5 - Pentane) January 2018 — December 2018 Swap 200 Bbls/day $56.364/Bbl The following summarizes the fair value of our open commodity derivatives as of December 31, 2017 and 2016 (in thousands): Balance Sheet Location Fair Value December 31, 2017 December 31, 2016 Derivatives not designated as hedging instruments Commodity derivatives Derivative assets $ 1,398 $ — Commodity derivatives Derivative liabilities (2,181 ) (4,880 ) The following summarizes the cash settlements and change in the fair value of our commodity derivatives (in thousands): Year Ended December 31, 2017 2016 2015 Derivatives not designated as hedging instruments Commodity derivatives Net cash (payment) receipt on derivative settlements $ (4,359 ) $ 6,132 $ 52,489 Non-cash fair value gain (loss) on derivatives 4,097 (11,616 ) (33,214 ) Commodity derivative (loss) gain $ (262 ) $ (5,484 ) $ 19,275 Derivative assets and liabilities, 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. 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, 2017, 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, 2017, 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 acquired in the Bolt-on Acquisition represents a Level 3 measurement. 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, 2017, we had no recurring Level 3 measurements. Nonrecurring Fair Value Measurements We recorded no impairment of our proved properties for the years ended December 31, 2017, and 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, 2017 Carrying Amount Fair Value Senior Notes, net $ 84,185 $ 74,798 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, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	8. Commitments and Contingencies At December 31, 2017, 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 $6.3 million at December 31, 2017. This estimate assumes the maximum potential bonus for 2017 is earned by each executive officer during 2017. 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 September 30, 2021. We also have non-cancelable operating lease commitments related to office equipment that expire by 2022. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2017 (in thousands): 2018 $ 852 2019 861 2020 875 2021 673 2022 4 Total $ 3,265 Rent expense under our lease arrangements amounted to $748,000, $1,025,000 and $1,002,000 for the years ended December 31, 2017, 2016 and 2015, 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, 2017
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, 2017 2016 2015 Property acquisition costs: Unproved properties $ 231 $ 17 $ 653 Proved properties(1) 17,331 — — Exploration costs 3,657 3,923 4,439 Development costs(2) 43,202 15,884 146,237 Total costs incurred $ 64,421 $ 19,824 $ 151,329 (1) For the year ended December 31, 2017, acquisition costs of proved properties included the fair value of assets acquired in the Bolt-On Acquisition. See Note 2 for additional disclosures related to the Bolt-On Acquisition. (2) For the years ended December 31, 2017, 2016 and 2015, development costs included $39,000, $36,000 and $151,000, 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, 2017 2016 2015 Revenues $ 105,349 $ 90,302 $ 131,336 Production costs (26,546 ) (27,467 ) (40,057 ) Exploration expense (3,657 ) (3,923 ) (4,439 ) Depletion (70,521 ) (79,044 ) (109,319 ) Impairment of oil and gas properties — — (220,197 ) Income tax benefit (expense) (1,641 ) 7,144 86,120 Results of operations $ 2,984 $ (12,988 ) $ (156,556 )

Disclosures About Oil and Gas P

Disclosures About Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2017
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, 2017, 2016 and 2015, 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 2017, 2016 and 2015. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows: 2017 2016 2015 Oil (per Bbl) $ 51.34 $ 42.69 $ 50.16 Natural gas liquids (per Bbl) $ 18.67 $ 14.12 $ 15.13 Gas (per Mcf) $ 2.99 $ 2.47 $ 2.64 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, 2017, 2016 and 2015, 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, 2015 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 Extensions and discoveries 10,546 9,975 76,710 33,307 Acquisition of minerals in place 710 394 2,808 1,572 Production(1) (1,107 ) (1,486 ) (11,148 ) (4,452 ) Revisions to previous estimates (10,120 ) 1,431 20,581 (5,259 ) Balance — December 31, 2017 50,060 57,948 441,228 181,545 (1) Production included 1,530 MMcf, 1,330 MMcf and 1,319 MMcf related to field fuel in 2015, 2016 and 2017, respectively. Total Proved Reserves Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Proved Developed Reserves: January 1, 2015 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 December 31, 2017 13,853 23,180 176,201 66,399 Proved Undeveloped Reserves: January 1, 2015 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 December 31, 2017 36,207 34,768 265,028 115,146 The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2017, 2016 and 2015: Year Ended December 31, 2017 Extensions and discoveries for 2017 were 33.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 MMBoe of proved reserves through the Bolt-On Acquisition, and we reclassified 17.7 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 9.4 MMBoe resulting from updated well performance and technical parameters and an increase of 3.1 MMBoe due to higher commodity prices We produced 4.5 MMBoe during 2017. This production included 1,319 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, 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. 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, 2017, 2016 and 2015 (in thousands): Years Ended December 31, 2017 2016 2015 Future cash flows $ 4,451,665 $ 3,319,551 $ 4,097,568 Future production costs (1,279,777 ) (1,054,211 ) (1,237,888 ) Future development costs (982,284 ) (829,926 ) (934,814 ) Future income tax expense (323,308 ) (132,834 ) (307,374 ) Future net cash flows 1,866,296 1,302,580 1,617,492 10% annual discount for estimated timing of cash flows (1,405,265 ) (1,004,825 ) (1,157,097 ) Standardized measure of discounted future net cash flows $ 461,031 $ 297,755 $ 460,395 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, 2017 2016 2015 Balance, beginning of period $ 297,755 $ 460,395 $ 1,055,815 Net change in sales and transfer prices and in production (lifting) costs related to future production 229,139 (191,841 ) (1,405,864 ) Changes in estimated future development costs (72,439 ) 17,405 231,900 Sales and transfers of oil and gas produced during the period (78,803 ) (62,835 ) (91,278 ) Net change due to acquisition of minerals in place 17,331 — — Net change due to extensions, discoveries and improved recovery 49,377 13,988 156,783 Net change due to revisions in quantity estimates (3,817 ) (25,236 ) (59,305 ) Previously estimated development costs incurred during the period 43,202 15,884 146,237 Accretion of discount 30,789 46,040 105,582 Other (1,677 ) (9,500 ) 6,915 Net change in income taxes (49,826 ) 33,455 313,610 Standardized Measure of discounted future net cash flows $ 461,031 $ 297,755 $ 460,395

Supplementary Data

Supplementary Data	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Supplementary Data	11. Supplementary Data Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts): 2017 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 28,417 $ 25,608 $ 24,969 $ 26,355 Net operating expenses (29,365 ) (29,543 ) (34,689 ) (31,460 ) Interest expense, net (5,370 ) (5,304 ) (4,916 ) (5,463 ) Gain on debt extinguishment — — — 5,053 Commodity derivative (loss) gain (1,377 ) (3,560 ) 1,231 3,444 Other income (expense) — 29 — 3 Loss before income tax benefit (7,695 ) (12,770 ) (13,405 ) (2,068 ) Income tax (benefit) provision (53,512 ) (4,258 ) (4,509 ) 138,700 Net income (loss) $ 45,817 $ (8,512 ) $ (8,896 ) $ (140,768 ) Basic net earnings (loss) applicable to common stockholders per common share $ 0.51 $ (0.10 ) $ (0.10 ) $ (2.00 ) Diluted net earnings (loss) applicable to common stockholders per common share $ 0.51 $ (0.10 ) $ (0.10 ) $ (2.00 ) 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 ) — Commodity derivative (loss) gain (2,901 ) 1,541 (6,667 ) 2,543 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 — — Commodity derivative gain (loss) 4,267 13,051 (4,623 ) 6,580 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 )

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Mineral interests in properties: Unproved leasehold costs $ 28,737 $ 33,596 Proved leasehold costs 60,077 44,643 Wells and related equipment and facilities 1,819,836 1,774,314 Support equipment 8,459 8,002 Uncompleted wells, equipment and facilities 13,468 9,219 Total costs 1,930,577 1,869,774 Less accumulated depreciation, depletion and amortization (850,301 ) (780,412 ) Net capitalized costs $ 1,080,276 $ 1,089,362 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, 2017 or 2016. 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, 2017, 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 $70.3 million, $78.7 million and $108.8 million for the years ended December 31, 2017, 2016 and 2015, 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, 2017 and 2016. 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 $237,000, $343,000 and $563,000 for the years ended December 31, 2017, 2016 and 2015, 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, 2017 and 2016. 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, 2017 or 2016. 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 2014 and forward and Texas income and margin tax returns for tax years 2014 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 currently have a valuation allowance of $0.5 million on our deferred tax assets, after accounting for the change in the corporate federal income tax rate under the Tax Cuts and Jobs Act.
Derivative Activity	Derivative Activity We record our open derivative instruments at fair value on our consolidated balance sheets as either derivative assets or liabilities. Cash settlements and changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur on our consolidated statements of operations under the caption entitled “commodity derivative (loss) gain.” We have not historically designated our derivative instruments as cash-flow hedges; however we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Derivative assets and derivative liabilities, 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.
Prepaid Expenses and Other Assets	Prepaid Expenses and Other Assets In April 2017, we entered into an agreement that secured pricing and availability of a dedicated hydraulic fracturing services crew. Under this agreement, we made a prepayment of $5 million, to be used as we completed wells. We have used $0.7 million of this prepayment related to hydraulic fracturing services provided during the first year of the agreement. As of December 31, 2017, we maintained an unused prepaid balance of $4.3 million in prepaid expenses and other current assets on our consolidated balance sheets related to this agreement. After December 31, 2017, we used an additional $0.5 million of this prepayment and $3.8 million of the unused prepaid balance was refunded to us.
Accrued Liabilities	Accrued Liabilities The following is a summary of our accrued liabilities at December 31, 2017 and 2016 (in thousands): 2017 2016 Capital expenditures accrual $ 1,522 $ 1,067 Operating expenses and other 6,551 6,750 Total $ 8,073 $ 7,817
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, 2017, 2016 and 2015.
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. Additionally, we recognize forfeitures of share-based compensation as they occur. 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, 2017 2016 2015 Income (numerator): Net (loss) income — basic $ (112,359 ) $ (52,243 ) $ (174,104 ) Weighted average shares (denominator): Weighted average shares — basic 83,404,104 41,488,206 40,464,283 Dilution effect of share-based compensation, treasury method (1) — — — Weighted average shares — diluted 83,404,104 41,488,206 40,464,283 Net (loss) income per share: Basic $ (1.35 ) $ (1.26 ) $ (4.30 ) Diluted $ (1.35 ) $ (1.26 ) $ (4.30 ) (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. No options were outstanding as of December 31, 2017, as they had expired.
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, 2017 or 2016.
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, 201 7, sales to American Midstream, LP (“AMID”), a successor to JP Energy Development, LP (“JP Energy”), and DCP Midstream, LP (“DCP”) accounted for approximately 52% and 47%, respectively, of our total sales. As of December 31, 2017, we had dedicated the majority of our oil production from Project Pangea through September 2022 to AMID. In addition, as of December 31, 2017, we had contracted to sell the majority of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2016, sales to DCP and JP Energy accounted for approximately 46% and 54%, respectively of our total sales. For the year ended December 31, 2015, sales to DCP and JP Energy accounted for approximately 36% and 63%, 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 (the “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 completed our detailed review of our individual purchaser contracts and we have evaluated the impact of this accounting standards update on our consolidated financial statements. We adopted this standard using the modified retrospective method of adoption on January 1, 2018. Adoption of this standard did not have a significant impact on our consolidated statements of operations or cash flows. We 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. Currently, the Company is evaluating the standard’s applicability to our various contractual arrangements. We believe that the adoption this standard will result in recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still 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, 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. In August 2017, FASB issued an accounting standards update for “Derivatives and Hedging,” impact our consolidated statements of operations or cash flows.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Oil and Gas Properties	Our oil and gas properties comprised the following (in thousands): December 31, 2017 2016 Mineral interests in properties: Unproved leasehold costs $ 28,737 $ 33,596 Proved leasehold costs 60,077 44,643 Wells and related equipment and facilities 1,819,836 1,774,314 Support equipment 8,459 8,002 Uncompleted wells, equipment and facilities 13,468 9,219 Total costs 1,930,577 1,869,774 Less accumulated depreciation, depletion and amortization (850,301 ) (780,412 ) Net capitalized costs $ 1,080,276 $ 1,089,362
Summary of Accrued Liabilities	The following is a summary of our accrued liabilities at December 31, 2017 and 2016 (in thousands): 2017 2016 Capital expenditures accrual $ 1,522 $ 1,067 Operating expenses and other 6,551 6,750 Total $ 8,073 $ 7,817
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, 2017 2016 2015 Income (numerator): Net (loss) income — basic $ (112,359 ) $ (52,243 ) $ (174,104 ) Weighted average shares (denominator): Weighted average shares — basic 83,404,104 41,488,206 40,464,283 Dilution effect of share-based compensation, treasury method (1) — — — Weighted average shares — diluted 83,404,104 41,488,206 40,464,283 Net (loss) income per share: Basic $ (1.35 ) $ (1.26 ) $ (4.30 ) Diluted $ (1.35 ) $ (1.26 ) $ (4.30 ) (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. No options were outstanding as of December 31, 2017, as they had expired.

Equity Exchange Transactions (T

Equity Exchange Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Exchange Transactions [Abstract]
Summary of Preliminary Estimated Fair Value of Assets Acquired and Liabilities Assumed	The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed as a result of the Bolt-On Acquisition (in thousands): Accounts receivable $ 558 Proved leasehold costs 13,865 Lease and well equipment 3,466 Total assets acquired 17,889 Accounts payable (106 ) Oil, NGLs and gas sales payable (255 ) Accrued liabilities (25 ) Asset retirement obligations (71 ) Total liabilities assumed (457 ) Estimated fair value of net assets acquired $ 17,432

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Long Term Debt	The following table provides a summary of our long-term debt at December 31, 2017, and December 31, 2016 (in thousands). December 31, 2017 December 31, 2016 Senior secured credit facility: Outstanding borrowings $ 291,000 $ 273,000 Debt issuance costs (1,725 ) (1,304 ) Senior secured credit facility, net 289,275 271,696 Senior notes: Principal 85,240 230,320 Debt issuance costs (1,055 ) (3,667 ) Senior notes, net 84,185 226,653 Total long-term debt $ 373,460 $ 498,349

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017, 2016 and 2015, is presented below: Shares Weighted Average Grant-Date Fair Value Nonvested at January 1, 2015 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 Granted 2,343,522 2.39 Vested (902,197 ) 6.73 Canceled (89,728 ) 5.17 Nonvested at December 31, 2017 3,304,661 $ 2.21

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	Our provision for income taxes comprised the following (in thousands): Years Ended December 31, 2017 2016 2015 Current: Federal $ (66 ) $ — $ (265 ) State — — — Total current provision for income taxes $ (66 ) $ — $ (265 ) Deferred: Federal $ 75,341 $ (24,957 ) $ (91,716 ) State 1,146 539 (1,424 ) Total deferred provision for income taxes $ 76,487 $ (24,418 ) $ (93,140 )
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, 2017 2016 2015 Statutory tax at 35% $ (12,578 ) $ (26,831 ) $ (93,628 ) State taxes, net of federal impact 528 578 (1,463 ) Share-based compensation tax shortfall 1,279 1,826 1,939 Permanent differences 11 11 26 Other differences 30 (2 ) (1,035 ) Change in federal tax rate (51,939 ) — — Write-off of deferred tax assets 139,090 — 756 Total $ 76,421 $ (24,418 ) $ (93,405 )
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, 2017 2016 Deferred tax assets: Net operating loss carryforwards $ 39,991 $ 155,018 Derivative liabilities 471 1,732 Other 533 892 Total deferred tax assets 40,995 157,642 Deferred tax liabilities: Difference in depreciation, depletion and capitalization methods — oil and gas properties (122,335 ) (162,501 ) Derivative assets (302 ) — Total deferred tax liabilities (122,637 ) (162,501 ) Valuation allowance (460 ) (756 ) Net deferred tax liability $ (82,102 ) $ (5,615 )

Derivative Instruments and Fa25

Derivative Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Commodity Derivatives Volumes and Prices	At December 31, 2017, we had the following commodity derivatives positions outstanding: Commodity and Period Contract Type Volume Transacted Contract Price Crude Oil January 2018 — December 2018 Swap 300 Bbls/day $50.00/Bbl January 2018 — March 2018 Collar 1,000 Bbls/day $50.00/Bbl - $55.05/Bbl January 2018 — June 2018 Collar 500 Bbls/day $55.00/Bbl - $60.00/Bbl 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 (C3 - Propane) January 2018 — March 2018 Swap 450 Bbls/day $30.24/Bbl NGLs (IC4 - Isobutane) January 2018 — March 2018 Swap 50 Bbls/day $36.12/Bbl NGLs (NC4 - Butane) January 2018 — March 2018 Swap 150 Bbls/day $35.70/Bbl After December 31, 2017, we entered into the following commodity derivative positions: Commodity and Period Contract Type Volume Transacted Contract Price Crude Oil January 2018 — September 2018 Swap 700 Bbls/day $60.50/Bbl April 2018 — September 2018 Swap 800 Bbls/day $60.50/Bbl NGLs (C2 - Ethane) February 2018 — December 2018 Swap 1,000 Bbls/day $11.424/Bbl NGLs (C3 - Propane) February 2018 — December 2018 Swap 600 Bbls/day $32.991/Bbl NGLs (IC4 - Isobutane) February 2018 — December 2018 Swap 50 Bbls/day $38.262/Bbl NGLs (NC4 - Butane) February 2018 — December 2018 Swap 200 Bbls/day $38.22/Bbl NGLs (C5 - Pentane) January 2018 — December 2018 Swap 200 Bbls/day $56.364/Bbl
Summary of Fair Value of Open Commodity Derivatives	The following summarizes the fair value of our open commodity derivatives as of December 31, 2017 and 2016 (in thousands): Balance Sheet Location Fair Value December 31, 2017 December 31, 2016 Derivatives not designated as hedging instruments Commodity derivatives Derivative assets $ 1,398 $ — Commodity derivatives Derivative liabilities (2,181 ) (4,880 )
Summary of Cash Settlements and Change in Fair Value of Commodity Derivatives	The following summarizes the cash settlements and change in the fair value of our commodity derivatives (in thousands): Year Ended December 31, 2017 2016 2015 Derivatives not designated as hedging instruments Commodity derivatives Net cash (payment) receipt on derivative settlements $ (4,359 ) $ 6,132 $ 52,489 Non-cash fair value gain (loss) on derivatives 4,097 (11,616 ) (33,214 ) Commodity derivative (loss) gain $ (262 ) $ (5,484 ) $ 19,275
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, 2017 Carrying Amount Fair Value Senior Notes, net $ 84,185 $ 74,798

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 (in thousands): 2018 $ 852 2019 861 2020 875 2021 673 2022 4 Total $ 3,265

Oil and Gas Producing Activit27

Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Property acquisition costs: Unproved properties $ 231 $ 17 $ 653 Proved properties(1) 17,331 — — Exploration costs 3,657 3,923 4,439 Development costs(2) 43,202 15,884 146,237 Total costs incurred $ 64,421 $ 19,824 $ 151,329 (1) For the year ended December 31, 2017, acquisition costs of proved properties included the fair value of assets acquired in the Bolt-On Acquisition. See Note 2 for additional disclosures related to the Bolt-On Acquisition. (2) For the years ended December 31, 2017, 2016 and 2015, development costs included $39,000, $36,000 and $151,000, 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, 2017 2016 2015 Revenues $ 105,349 $ 90,302 $ 131,336 Production costs (26,546 ) (27,467 ) (40,057 ) Exploration expense (3,657 ) (3,923 ) (4,439 ) Depletion (70,521 ) (79,044 ) (109,319 ) Impairment of oil and gas properties — — (220,197 ) Income tax benefit (expense) (1,641 ) 7,144 86,120 Results of operations $ 2,984 $ (12,988 ) $ (156,556 )

Disclosures About Oil and Gas28

Disclosures About Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017, 2016 and 2015. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows: 2017 2016 2015 Oil (per Bbl) $ 51.34 $ 42.69 $ 50.16 Natural gas liquids (per Bbl) $ 18.67 $ 14.12 $ 15.13 Gas (per Mcf) $ 2.99 $ 2.47 $ 2.64
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, 2017, 2016 and 2015, 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, 2015 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 Extensions and discoveries 10,546 9,975 76,710 33,307 Acquisition of minerals in place 710 394 2,808 1,572 Production(1) (1,107 ) (1,486 ) (11,148 ) (4,452 ) Revisions to previous estimates (10,120 ) 1,431 20,581 (5,259 ) Balance — December 31, 2017 50,060 57,948 441,228 181,545 (1) Production included 1,530 MMcf, 1,330 MMcf and 1,319 MMcf related to field fuel in 2015, 2016 and 2017, respectively. Total Proved Reserves Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Proved Developed Reserves: January 1, 2015 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 December 31, 2017 13,853 23,180 176,201 66,399 Proved Undeveloped Reserves: January 1, 2015 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 December 31, 2017 36,207 34,768 265,028 115,146
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, 2017, 2016 and 2015 (in thousands): Years Ended December 31, 2017 2016 2015 Future cash flows $ 4,451,665 $ 3,319,551 $ 4,097,568 Future production costs (1,279,777 ) (1,054,211 ) (1,237,888 ) Future development costs (982,284 ) (829,926 ) (934,814 ) Future income tax expense (323,308 ) (132,834 ) (307,374 ) Future net cash flows 1,866,296 1,302,580 1,617,492 10% annual discount for estimated timing of cash flows (1,405,265 ) (1,004,825 ) (1,157,097 ) Standardized measure of discounted future net cash flows $ 461,031 $ 297,755 $ 460,395
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, 2017 2016 2015 Balance, beginning of period $ 297,755 $ 460,395 $ 1,055,815 Net change in sales and transfer prices and in production (lifting) costs related to future production 229,139 (191,841 ) (1,405,864 ) Changes in estimated future development costs (72,439 ) 17,405 231,900 Sales and transfers of oil and gas produced during the period (78,803 ) (62,835 ) (91,278 ) Net change due to acquisition of minerals in place 17,331 — — Net change due to extensions, discoveries and improved recovery 49,377 13,988 156,783 Net change due to revisions in quantity estimates (3,817 ) (25,236 ) (59,305 ) Previously estimated development costs incurred during the period 43,202 15,884 146,237 Accretion of discount 30,789 46,040 105,582 Other (1,677 ) (9,500 ) 6,915 Net change in income taxes (49,826 ) 33,455 313,610 Standardized Measure of discounted future net cash flows $ 461,031 $ 297,755 $ 460,395

Supplementary Data (Tables)

Supplementary Data (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts): 2017 Quarters Ended December 31 September 30 June 30 March 31 Net revenues $ 28,417 $ 25,608 $ 24,969 $ 26,355 Net operating expenses (29,365 ) (29,543 ) (34,689 ) (31,460 ) Interest expense, net (5,370 ) (5,304 ) (4,916 ) (5,463 ) Gain on debt extinguishment — — — 5,053 Commodity derivative (loss) gain (1,377 ) (3,560 ) 1,231 3,444 Other income (expense) — 29 — 3 Loss before income tax benefit (7,695 ) (12,770 ) (13,405 ) (2,068 ) Income tax (benefit) provision (53,512 ) (4,258 ) (4,509 ) 138,700 Net income (loss) $ 45,817 $ (8,512 ) $ (8,896 ) $ (140,768 ) Basic net earnings (loss) applicable to common stockholders per common share $ 0.51 $ (0.10 ) $ (0.10 ) $ (2.00 ) Diluted net earnings (loss) applicable to common stockholders per common share $ 0.51 $ (0.10 ) $ (0.10 ) $ (2.00 ) 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 ) — Commodity derivative (loss) gain (2,901 ) 1,541 (6,667 ) 2,543 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 — — Commodity derivative gain (loss) 4,267 13,051 (4,623 ) 6,580 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 )

Summary of Significant Accoun30

Summary of Significant Accounting Policies - Summary of Oil and Gas Properties (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Mineral interests in properties:
Unproved leasehold costs	$ 28,737	$ 33,596
Proved leasehold costs	60,077	44,643
Wells and related equipment and facilities	1,819,836	1,774,314
Support equipment	8,459	8,002
Uncompleted wells, equipment and facilities	13,468	9,219
Total costs	1,930,577	1,869,774
Less accumulated depreciation, depletion and amortization	(850,301)	(780,412)
Net capitalized costs	$ 1,080,276	$ 1,089,362

Summary of Significant Accoun31

Summary of Significant Accounting Policies - Additional Information (Detail)	Jan. 01, 2018USD ($)	Jan. 02, 2016USD ($)	Apr. 30, 2017USD ($)	Dec. 31, 2017USD ($)Segment	Dec. 31, 2016USD ($)Well	Dec. 31, 2015USD ($)Well
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				70,300,000	$ 78,700,000	$ 108,800,000
Impairment of oil and gas properties and equipment				0	0	220,197,000
Depreciation expense for other property and equipment				$ 237,000	343,000	563,000
Tax benefit				50.00%
Uncertain tax positions				$ 0	0
Valuation allowance on deferred tax assets after accounting for change in corporate federal income tax rate under tax cuts and job act				500,000
Prepayment under the agreement			$ 5,000,000
Utilization of prepayment related to hydraulic fracturing services provided				700,000
Prepaid expenses and other current assets				$ 5,486,000	2,834,000
Number of days in which payment is to be made				30 days
Exploration expenses				$ 3,657,000	$ 3,923,000	$ 4,439,000
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				47.00%	46.00%	36.00%
Customer Concentration Risk [Member] | JP Energy Permian, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers				52.00%	54.00%	63.00%
Drilling Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Exploration expenses					$ 2,200,000
Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Prepayment additional used amount	$ 500,000
Unused Prepaid Balance [Member]
Summary Of Significant Accounting Policies [Line Items]
Prepaid expenses and other current assets				$ 4,300,000
Unused Prepaid Balance [Member] | Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Proceeds from prepayment under the agreement	$ 3,800,000
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	0	$ 214,700,000
Unproved Property Impairment [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of oil and gas properties and equipment				$ 0	$ 0	$ 5,500,000

Summary of Significant Accoun32

Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets [Abstract]
Capital expenditures accrual	$ 1,522	$ 1,067
Operating expenses and other	6,551	6,750
Total	$ 8,073	$ 7,817

Summary of Significant Accoun33

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	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, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Net loss	$ 45,817	$ (8,512)	$ (8,896)	$ (140,768)	$ (13,475)	$ (9,073)	$ (16,035)	$ (13,660)	$ (5,759)	$ (148,787)	$ (11,850)	$ (7,708)	$ (112,359)	$ (52,243)	$ (174,104)
Weighted average shares — basic													83,404,104	41,488,206	40,464,283
Weighted average shares — diluted													83,404,104	41,488,206	40,464,283
Basic	$ 0.51	$ (0.10)	$ (0.10)	$ (2)	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ (1.35)	$ (1.26)	$ (4.30)
Diluted	$ 0.51	$ (0.10)	$ (0.10)	$ (2)	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ (1.35)	$ (1.26)	$ (4.30)

Summary of Significant Accoun34

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	Dec. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares subject to stock options, outstanding			0
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

Equity Exchange Transactions -

Equity Exchange Transactions - Additional Information (Detail) - USD ($)

Sep. 01, 2017

Mar. 22, 2017

Jan. 27, 2017

Nov. 02, 2016

Dec. 31, 2017

Mar. 31, 2017

Dec. 31, 2015

Sep. 30, 2015

Dec. 31, 2017

Dec. 31, 2015

Jan. 26, 2017

Dec. 31, 2016

Equity Exchange Transactions [Line Items]

Common stock, par value

$ 0.01

$ 0.01

$ 0.01

Common stock, shares authorized

180,000,000

180,000,000

90,000,000

Gain recognized on exchange of senior notes

$ 5,053,000

$ 9,080,000

$ 1,483,000

$ 5,053,000

$ 10,563,000

Equity issuance costs

$ 2,780,000

NOLs, limitations on use

The Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the usage of our pre-change net operating losses (“NOLs”) in the future.

Reduction value of net operating losses deferred tax assets

$ 139,090,000

$ 756,000

Bolt-On Acquisition [Member]

Equity Exchange Transactions [Line Items]

Common stock, par value

$ 0.01

Date of definitive agreement to acquire producing properties

Nov. 1, 2017

Common stock, shares issued

7,573,403

Effective date of acquisition

Nov. 20, 2017

Revenue

$ 500,000

Bolt-On Acquisition [Member] | General and Administrative Expenses [Member]

Equity Exchange Transactions [Line Items]

Acquisition-related costs

$ 100,000

7% Senior Notes Due 2021 [Member]

Equity Exchange Transactions [Line Items]

Debt exchange to common stock, principal amount

145,100,000

Reduction of debt interest payment for remaining term of senior notes

$ 44,300,000

7% Senior Notes Due 2021 [Member] | Initial Exchange [Member] | Wilks [Member]

Equity Exchange Transactions [Line Items]

Debt exchange to common stock, principal amount

$ 130,552,000

Common stock, par value

$ 0.01

Common stock, shares authorized

90,000,000

180,000,000

Payments of accrued interest

$ 1,100,000

Debt conversion, interest rate of debt

7.00%

Debt exchange date

Jan. 27, 2017

7% Senior Notes Due 2021 [Member] | Initial Exchange [Member] | Common Stock [Member] | Wilks [Member]

Equity Exchange Transactions [Line Items]

Debt exchange to common stock, shares issued

39,165,600

7% Senior Notes Due 2021 [Member] | Follow-On Exchange [Member]

Equity Exchange Transactions [Line Items]

Debt exchange to common stock, principal amount

$ 14,528,000

Debt exchange date

Mar. 22, 2017

7% Senior Notes Due 2021 [Member] | Follow-On Exchange [Member] | Common Stock [Member]

Equity Exchange Transactions [Line Items]

Debt exchange to common stock, shares issued

4,009,728

Equity Exchange Transactions 36

Equity Exchange Transactions - Summary of Preliminary Estimated Fair Value of Assets Acquired and Liabilities Assumed (Detail) - Bolt-On Acquisition [Member] $ in Thousands	Nov. 20, 2017USD ($)
Business Acquisition [Line Items]
Accounts receivable	$ 558
Proved leasehold costs	13,865
Lease and well equipment	3,466
Total assets acquired	17,889
Accounts payable	(106)
Oil, NGLs and gas sales payable	(255)
Accrued liabilities	(25)
Asset retirement obligations	(71)
Total liabilities assumed	(457)
Estimated fair value of net assets acquired	$ 17,432

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 21, 2017	Dec. 31, 2016	May 03, 2016	Jun. 30, 2013
Debt Instrument [Line Items]
Senior secured credit facility, net	$ 289,275		$ 271,696
Senior notes, net	84,185		226,653
Total long-term debt	373,460		498,349
Senior Notes [Member]
Debt Instrument [Line Items]
Principal	85,240		230,320
Debt issuance costs	(1,055)		(3,667)
Senior notes, net	84,185		226,653		$ 250,000
Senior Secured Credit Facility [Member]
Debt Instrument [Line Items]
Outstanding borrowings	291,000		273,000
Debt issuance costs	(1,725)	$ (1,000)	(1,304)	$ (200)
Senior secured credit facility, net	$ 289,275		$ 271,696

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Dec. 21, 2017USD ($)	Dec. 20, 2017	Dec. 15, 2017USD ($)	May 03, 2016USD ($)	Jun. 30, 2013USD ($)	Mar. 31, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2016USD ($)
Line of Credit Facility [Line Items]
Debt issuance costs written off							$ 563,000				$ 563,000
Senior notes, net										$ 84,185,000	226,653,000
Gain on debt extinguishment						$ 5,053,000		$ 9,080,000	$ 1,483,000	5,053,000		$ 10,563,000
Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt issuance costs										1,055,000	3,667,000
Senior notes, net					$ 250,000,000					84,185,000	226,653,000
Stated interest rate					7.00%
Debt instrument payment of interest					semi-annually on June 15 and December 15
Semi-annual interest payment amount			$ 3,000,000
Proceeds from issuance of senior notes											243,000,000
Debt exchange to common stock, principal amount										145,100,000
Reduced future interest payments amount										44,300,000
Repurchased senior notes face value								$ 19,700,000				19,700,000
Repurchased price of senior notes												8,800,000
Gain on debt extinguishment												$ 10,600,000
Senior notes outstanding										85,240,000	230,320,000
Senior Notes [Member] | Wilks [Member]
Line of Credit Facility [Line Items]
Senior notes outstanding										43,000,000
Senior Notes [Member] | Wilks [Member] | Current Liability [Member]
Line of Credit Facility [Line Items]
Accrued interest										100,000
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, 2020	May 7, 2019								May 7, 2020
Additional borrowing base, re-determination description										We, or the lenders, can each request one additional borrowing base redetermination each calendar year.
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 2% to 3%, or the sum of the LIBOR rate plus an applicable margin ranging from 3% to 4%. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available,
Senior secured credit facility										$ 291,000,000	273,000,000
Interest rate applicable of senior secured credit facility										4.50%
Unused letters of credit outstanding										$ 300,000	600,000
Production from liens covering the oil and gas properties										95.00%
Increase in applicable margin rates on borrowings	0.50%			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	$ 1,000,000			$ 200,000						$ 1,725,000	$ 1,304,000
Required percentage of anticipated production to be hedged	50.00%
Consolidated interest coverage ratio										2.7
Consolidated modified current ratio										2.1
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 that requires us to maintain a ratio of (i) consolidated EBITDAX for the period of four fiscal quarters then ending to (ii) Cash Interest Expense for such period as of the last day of any fiscal quarter of not less than 1.5 to 1.0 through December 31, 2017, a ratio of not less than 1.75 to 1.0 through December 31, 2018, a ratio of not less than 2.25 to 1.0 through December 31, 2019, and 2.5 to 1.0 thereafter. EBITDAX is defined as consolidated net (loss) income plus (i) interest expense, net, (ii) income tax provision (benefit), (iii) depreciation, depletion, amortization, (iv) exploration expenses and (v) other noncash loss or expense (including share-based compensation and the change in fair value of any commodity derivatives), less noncash income. Cash Interest Expense is calculated as interest expense, net less amortization of debt issuance costs. At December 31, 2017, our consolidated interest coverage ratio was 2.7 to 1.0; a consolidated modified current ratio covenant 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 consolidated modified current ratio is defined as the ratio of (i) current assets plus funds available under our revolving credit facility, less the current derivative asset, to (ii) current liabilities less the current derivative liability. At December 31, 2017, our consolidated modified current ratio was 2.0 to 1.0; and a consolidated total leverage ratio covenant that requires a maximum permitted ratio of (i) Total Debt to (ii) EBITDAX for the period of four fiscal quarters then ending of 5.0 to 1.0, as of the last day of any fiscal quarter from March 31, 2019, through June 30, 2019, thereafter 4.75 to 1.0 as of the last day of any fiscal quarter through December 31, 2019, and (iii) 4.0 to 1.0 as of the last day of any fiscal quarter thereafter. Total Debt is defined as the face or principal amount of debt. At December 31, 2017, our consolidated modified total leverage ratio was 6.9 to 1.0.
Minimum interest coverage ratio										1.5
Minimum interest coverage ratio, through December 31, 2018										1.75
Minimum interest coverage ratio, through December 31, 2019										2.25
Interest coverage ratio, thereafter										2.5
Senior Secured Credit Facility [Member] | Covenants Agreements Two [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										2.00%
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										3.00%
Senior Secured Credit Facility [Member] | Maximum [Member] | Covenants Agreements Three [Member]
Line of Credit Facility [Line Items]
Leverage ratio, March 31, 2019										5
Leverage ratio, through June 30, 2019										5
Leverage ratio, September 30, 2019										4.75
Leverage ratio, through December 31, 2019										4.75
Leverage ratio, thereafter										4
Senior Secured Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Senior secured credit facility, marginal percentage										3.00%
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										4.00%

Termination Costs - Additional

Termination Costs - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2017	Dec. 31, 2015
Restructuring Cost and Reserve [Line Items]
Severance expenses	$ 1,400,000		$ 1,436,000
Employee Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance expenses		$ 0
Employee Severance [Member] | General and Administrative Expense [Member]
Restructuring Cost and Reserve [Line Items]
Benefit recorded in share-based compensation expense		$ 300,000

Share-Based Compensation - Addi

Share-Based Compensation - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	$ 4,700,000	$ 6,300,000	$ 8,000,000
Shares subject to stock options, granted	0	0	0
Shares subject to stock options, expired	38,525
Shares subject to stock options, outstanding	0
Number of stock options exercised	0	0	0
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	$ 333,000	$ 338,000	$ 404,000
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%
Nonvested Shares [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares grant	2,343,522	1,318,229	1,278,329
Average grant date fair value	$ 5,600,000	$ 2,500,000	$ 6,200,000
Unrecognized compensation expense related to nonvested shares	$ 4,000,000
Nonvested outstanding weighted average remaining service period	2 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	$ 800,000	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	1,600,000
Cash Settled Performance Shares [Member] | Non-Current Liability [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation, liability	500,000
Non-Employee Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	$ 449,000	$ 214,000	$ 735,000
Executive Officers [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Service period	3 years
Executive Officers [Member] | Nonvested Shares [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Additional shares grant	1,492,652	550,272	724,249
Additional share grant fair value	$ 3,600,000	$ 300,000	$ 4,500,000
Executive Officers [Member] | Cash Settled Performance Shares [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of share awards		1,100,543
Fair market value of shares subject to performance conditions		$ 1,000,000
Service period		2 years
Fair market value of shares		$ 1,000,000
Executive Officers [Member] | Cash Settled Performance Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair market value of shares subject to performance conditions	$ 2,400,000
Subsequent restricted share award	774,590
Fair market value of shares	$ 2,400,000
Executive Officers [Member] | Restricted Shares Total Shareholder Return Performance Stock Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair market value of shares subject to performance conditions	$ 800,000
Subsequent restricted share award	387,295
Fair market value of shares	$ 800,000
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Nonvested Shares, Beginning Balance	1,953,064	1,735,256	1,122,410
Nonvested Shares, Granted	2,343,522	1,318,229	1,278,329
Nonvested Shares, Vested	(902,197)	(992,461)	(419,222)
Nonvested Shares, Canceled	(89,728)	(107,960)	(246,261)
Nonvested Shares, Ending Balance	3,304,661	1,953,064	1,735,256
Weighted Average Grant-Date Fair Value, Nonvested, Beginning Balance	$ 4.39	$ 8.60	$ 16.52
Weighted Average Grant-Date Fair Value, Nonvested, Granted	2.39	1.90	4.87
Weighted Average Grant-Date Fair Value, Nonvested, Vested	6.73	7.03	15.26
Weighted Average Grant-Date Fair Value, Nonvested, Canceled	5.17	17.33	14.30
Weighted Average Grant-Date Fair Value, Nonvested, Ending Balance	$ 2.21	$ 4.39	$ 8.60

Income Taxes - Schedule of Prov

Income Taxes - Schedule of Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal	$ (66)		$ (265)
Total current provision for income taxes	(66)		(265)
Deferred:
Federal	75,341	$ (24,957)	(91,716)
State	1,146	539	(1,424)
Total deferred provision for income taxes	$ 76,487	$ (24,418)	$ (93,140)

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	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, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Statutory tax at 35%													$ (12,578)	$ (26,831)	$ (93,628)
State taxes, net of federal impact													528	578	(1,463)
Share-based compensation tax shortfall													1,279	1,826	1,939
Permanent differences													11	11	26
Other differences													30	(2)	(1,035)
Change in federal tax rate													(51,939)
Write-off of deferred tax assets													139,090		756
Total	$ (53,512)	$ (4,258)	$ (4,509)	$ 138,700	$ (3,571)	$ (4,915)	$ (8,687)	$ (7,245)	$ (284)	$ (81,756)	$ (7,369)	$ (3,996)	$ 76,421	$ (24,418)	$ (93,405)

Income Taxes - Total Income T44

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	Jan. 02, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
NOLs, limitations on use			The Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the usage of our pre-change net operating losses (“NOLs”) in the future.
Reduction value of net operating losses deferred tax assets			$ 139,090,000		$ 756,000
Statutory tax rate			35.00%	35.00%	35.00%
Change in federal tax rate income tax expense benefit			$ 51,939,000
Share-based compensation tax shortfall			1,279,000	$ 1,826,000	$ 1,939,000
Net deferred tax assets and liabilities recorded as long-term liability			82,100,000	5,600,000
Valuation allowance on deferred tax assets after accounting for change in corporate federal income tax rate under tax cuts and job act			460,000	$ 756,000
Federal [Member]
Income Taxes [Line Items]
Net operating loss carryforwards			$ 190,400
Net operating loss carryforwards expiration start year			2,030
Net operating loss carryforwards expiration ending year			2,037
New Accounting Pronouncement, Early Adoption, Effect [Member]
Income Taxes [Line Items]
Increase in accumulated earnings and NOLs	$ 1,700,000
Scenario Forecast [Member]
Income Taxes [Line Items]
Statutory tax rate		21.00%

Income Taxes - Significant Comp

Income Taxes - Significant Components of Net Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 39,991	$ 155,018
Derivative liabilities	471	1,732
Other	533	892
Total deferred tax assets	40,995	157,642
Difference in depreciation, depletion and capitalization methods — oil and gas properties	(122,335)	(162,501)
Derivative assets	(302)
Total deferred tax liabilities	(122,637)	(162,501)
Valuation allowance	(460)	(756)
Net deferred tax liability	$ (82,102)	$ (5,615)

Derivative Instruments and Fa47

Derivative Instruments and Fair Value Measurements - Commodity Derivatives Volumes and Prices (Detail)	12 Months Ended
	Dec. 31, 2017MMBTU$ / bbl$ / MMBTUbbl
Crude Oil January 2018 – December 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	300
Contract Price	50
Crude Oil January 2018 – March 2018 Contract [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	1,000
Crude Oil January 2018 – March 2018 Contract [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price	50
Crude Oil January 2018 – March 2018 Contract [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price	55.05
Crude Oil January 2018 – June 2018 Contract [Member] | Collar [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	500
Crude Oil January 2018 – June 2018 Contract [Member] | Collar [Member] | Minimum [Member]
Derivatives Fair Value [Line Items]
Contract Price	55
Crude Oil January 2018 – June 2018 Contract [Member] | Collar [Member] | Maximum [Member]
Derivatives Fair Value [Line Items]
Contract Price	60
Natural Gas January 2018 - December 2018 Contract One [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU	200,000
Contract Price | $ / MMBTU	3.085
Natural Gas January 2018 - December 2018 Contract Two [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | MMBTU	250,000
Contract Price | $ / MMBTU	3.084
NGLs (C3 - Propane) January 2018 - March 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	450
Contract Price	30.24
NGLs (IC4 - Isobutane) January 2018 - March 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	50
Contract Price	36.12
NGLs (NC4 - Butane) January 2018 - March 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	150
Contract Price	35.70
Crude Oil January 2018 – September 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	700
Contract Price	60.50
Crude Oil April 2018 – September 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	800
Contract Price	60.50
NGLs (C2 - Ethane) February 2018 - December 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	1,000
Contract Price	11.424
NGLs (C3 - Propane) February 2018 - December 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	600
Contract Price	32.991
NGLs (IC4 - Isobutane) February 2018 - December 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	50
Contract Price	38.262
NGLs (NC4 - Butane) February 2018 - December 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	200
Contract Price	38.22
NGLs (C5 - Pentane) January 2018 - December 2018 Contract [Member] | Swap [Member]
Derivatives Fair Value [Line Items]
Volume Transacted | bbl	200
Contract Price	56.364

Derivative Instruments and Fa48

Derivative Instruments and Fair Value Measurements - Summary of Fair Value of Open Commodity Derivatives (Detail) - Commodity Derivatives [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives Fair Value [Line Items]
Derivatives not designated as hedging instruments, Derivatives assets, Fair Value	$ 1,398
Derivatives not designated as hedging instruments, Derivatives liabilities, Fair Value	$ (2,181)	$ (4,880)

Derivative Instruments and Fa49

Derivative Instruments and Fair Value Measurements - Summary of Cash Settlements and Change in Fair Value of Commodity Derivatives (Detail) - Derivatives Not Designated as Hedging Instruments [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Commodity derivative (loss) gain	$ (262)	$ (5,484)	$ 19,275
Net Cash (Payment) Receipt on derivatives Settlements [Member]
Derivatives Fair Value [Line Items]
Commodity derivative (loss) gain	(4,359)	6,132	52,489
Non-Cash Fair Value Gain (Loss) on Derivatives [Member]
Derivatives Fair Value [Line Items]
Commodity derivative (loss) gain	$ 4,097	$ (11,616)	$ (33,214)

Derivative Instruments and Fa50

Derivative Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Impairment of oil and gas properties and equipment	$ 0	$ 0	$ 220,197,000
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	$ 0	$ 214,700,000

Derivative Instruments and Fa51

Derivative Instruments and Fair Value Measurements - Summary of Financial Instruments Not Recorded at Fair Value (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior Notes, net	$ 84,185
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior Notes, net	$ 74,798

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017USD ($)ExecutiveOfficer	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
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	Sep. 30, 2021
Non-Cancelable lease agreement for office equipment, expiration year	2,022
Rent expense under lease arrangements	$ 748,000	1,025,000	$ 1,002,000
Legal settlement received from a service provider		$ 1,100,000
Employment Agreements [Member]
Other Commitments [Line Items]
Commitment under contracts	$ 6,300,000

Commitments and Contingencies53

Commitments and Contingencies - Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,018	$ 852
2,019	861
2,020	875
2,021	673
2,022	4
Total	$ 3,265

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 (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Unproved properties	$ 231	$ 17	$ 653
Proved properties	17,331
Exploration costs	3,657	3,923	4,439
Development costs	43,202	15,884	146,237
Total costs incurred	$ 64,421	$ 19,824	$ 151,329

Oil and Gas Producing Activit55

Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$ 43,202,000	$ 15,884,000	$ 146,237,000
Non-cash Asset Retirement Obligations [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$ 39,000	$ 36,000	$ 151,000

Oil and Gas Producing Activit56

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Revenues	$ 105,349,000	$ 90,302,000	$ 131,336,000
Production costs	(26,546,000)	(27,467,000)	(40,057,000)
Exploration expense	(3,657,000)	(3,923,000)	(4,439,000)
Depletion	(70,521,000)	(79,044,000)	(109,319,000)
Impairment of oil and gas properties	0	0	(220,197,000)
Income tax benefit (expense)	(1,641,000)	7,144,000	86,120,000
Results of operations	$ 2,984,000	$ (12,988,000)	$ (156,556,000)

Disclosures About Oil and Gas57

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, 2017$ / bbl$ / Mcf	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf
Oil (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	51.34	42.69	50.16
NGLs (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	18.67	14.12	15.13
Natural Gas (MMcf) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices | $ / Mcf	2.99	2.47	2.64

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 (Detail)	12 Months Ended
	Dec. 31, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf
Reserve Quantities [Line Items]
Production | MMcf	(1,319)	(1,330)	(1,530)
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | MBoe	156,377	166,646	146,248
Extensions and discoveries | MBoe	33,307	16,651	34,895
Acquisition of minerals in place | MBoe	1,572
Production | MBoe	(4,452)	(4,759)	(5,787)
Revisions to previous estimates | MBoe	(5,259)	(22,161)	(8,710)
Proved Developed and Proved Undeveloped Reserves, Ending Balance | MBoe	181,545	156,377	166,646
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	50,031	54,496	55,338
Extensions and discoveries	10,546	6,529	11,054
Acquisition of minerals in place	710
Production	(1,107)	(1,275)	(1,882)
Revisions to previous estimates	(10,120)	(9,719)	(10,014)
Proved Developed and Proved Undeveloped Reserves, Ending Balance	50,060	50,031	54,496
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	47,634	49,486	40,907
Extensions and discoveries	9,975	4,564	10,630
Acquisition of minerals in place	394
Production	(1,486)	(1,529)	(1,694)
Revisions to previous estimates	1,431	(4,887)	(357)
Proved Developed and Proved Undeveloped Reserves, Ending Balance	57,948	47,634	49,486
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | MMcf	352,277	375,988	300,020
Extensions and discoveries | MMcf	76,710	33,347	79,268
Acquisition of minerals in place | MMcf	2,808
Production | MMcf	(11,148)	(11,734)	(13,262)
Revisions to previous estimates | MMcf	20,581	(45,324)	9,962
Proved Developed and Proved Undeveloped Reserves, Ending Balance | MMcf	441,228	352,277	375,988

Disclosures About Oil and Gas59

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, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf
Reserve Quantities [Line Items]
Field fuel | MMcf	1,319	1,330	1,530
Proved Developed Reserves | MBoe	66,399	58,875	61,856	60,220
Proved Undeveloped Reserves | MBoe	115,146	97,502	104,790	86,028
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Field fuel	1,107	1,275	1,882
Proved Developed Oil Reserves	13,853	13,466	15,667	17,978
Proved Undeveloped Oil Reserves	36,207	36,565	38,829	37,360
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Field fuel	1,486	1,529	1,694
Proved Developed Oil Reserves	23,180	20,375	20,414	19,082
Proved Undeveloped Oil Reserves	34,768	27,259	29,072	21,825
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Field fuel | MMcf	11,148	11,734	13,262
Proved Developed Oil Reserves | MMcf	176,201	150,208	154,652	138,961
Proved Undeveloped Oil Reserves | MMcf	265,028	202,069	221,335	161,059

Disclosures About Oil and Gas60

Disclosures About Oil and Gas Producing Activities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017MBoeMMcf	Dec. 31, 2016MBoeMMcf	Dec. 31, 2015MBoeMMcf
Extractive Industries [Abstract]
Extensions and discoveries	33,307	16,651	34,895
Acquisition of proved reserves	1,572
Economic revisions	17,700	22,400	11,900
Increased revisions due to cost reduction, updated well Performance and technical parameters	9,400	2,100	13,000
Significant changes in reserves	Extensions and discoveries for 2017 were 33.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 MMBoe of proved reserves through the Bolt-On Acquisition, and we reclassified 17.7 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 9.4 MMBoe resulting from updated well performance and technical parameters and an increase of 3.1 MMBoe due to higher commodity prices	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.
Period for reclassification of proved reserves to unproved reserves	5 years	5 years	5 years
Increased revisions due to higher commodity prices	3,100
Production	4,500	4,800	5,800
Field fuel | MMcf	1,319	1,330	1,530
Decreased revisions due to lower commodity prices		1,900	9,800

Disclosures About Oil and Gas61

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, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Future cash flows	$ 4,451,665	$ 3,319,551	$ 4,097,568
Future production costs	(1,279,777)	(1,054,211)	(1,237,888)
Future development costs	(982,284)	(829,926)	(934,814)
Future income tax expense	(323,308)	(132,834)	(307,374)
Future net cash flows	1,866,296	1,302,580	1,617,492
10% annual discount for estimated timing of cash flows	(1,405,265)	(1,004,825)	(1,157,097)
Standardized measure of discounted future net cash flows	$ 461,031	$ 297,755	$ 460,395	$ 1,055,815

Disclosures About Oil and Gas62

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Standardized measure of discounted future net cash flows, Beginning balance	$ 297,755	$ 460,395	$ 1,055,815
Net change in sales and transfer prices and in production (lifting) costs related to future production	229,139	(191,841)	(1,405,864)
Changes in estimated future development costs	(72,439)	17,405	231,900
Sales and transfers of oil and gas produced during the period	(78,803)	(62,835)	(91,278)
Net change due to acquisition of minerals in place	17,331
Net change due to extensions, discoveries and improved recovery	49,377	13,988	156,783
Net change due to revisions in quantity estimates	(3,817)	(25,236)	(59,305)
Previously estimated development costs incurred during the period	43,202	15,884	146,237
Accretion of discount	30,789	46,040	105,582
Other	(1,677)	(9,500)	6,915
Net change in income taxes	(49,826)	33,455	313,610
Standardized Measure of discounted future net cash flows	$ 461,031	$ 297,755	$ 460,395

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	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, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Net revenues	$ 28,417	$ 25,608	$ 24,969	$ 26,355	$ 26,505	$ 23,749	$ 22,433	$ 17,615	$ 25,492	$ 33,941	$ 38,605	$ 33,298	$ 105,349	$ 90,302	$ 131,336
Net operating expenses	(29,365)	(29,543)	(34,689)	(31,460)	(33,564)	(32,201)	(34,534)	(34,869)	(38,671)	(272,462)	(46,970)	(45,686)	(125,057)	(135,168)	(403,789)
Interest expense, net	(5,370)	(5,304)	(4,916)	(5,463)	(7,086)	(7,067)	(6,808)	(6,298)	(6,436)	(6,465)	(6,243)	(5,922)	(21,053)	(27,259)	(25,066)
Gain on debt extinguishment				5,053					9,080	1,483			5,053		10,563
Write-off of debt issuance costs							(563)							(563)
Commodity derivative (loss) gain	(1,377)	(3,560)	1,231	3,444	(2,901)	1,541	(6,667)	2,543	4,267	13,051	(4,623)	6,580	(262)	(5,484)	19,275
Other income (expense)		29		3		(10)	1,417	104	225	(91)	12	26	32	1,511	172
LOSS BEFORE INCOME TAX PROVISON (BENEFIT)	(7,695)	(12,770)	(13,405)	(2,068)	(17,046)	(13,988)	(24,722)	(20,905)	(6,043)	(230,543)	(19,219)	(11,704)	(35,938)	(76,661)	(267,509)
Income tax (benefit) provision	(53,512)	(4,258)	(4,509)	138,700	(3,571)	(4,915)	(8,687)	(7,245)	(284)	(81,756)	(7,369)	(3,996)	76,421	(24,418)	(93,405)
NET LOSS	$ 45,817	$ (8,512)	$ (8,896)	$ (140,768)	$ (13,475)	$ (9,073)	$ (16,035)	$ (13,660)	$ (5,759)	$ (148,787)	$ (11,850)	$ (7,708)	$ (112,359)	$ (52,243)	$ (174,104)
Basic net earnings (loss) applicable to common stockholders per common share	$ 0.51	$ (0.10)	$ (0.10)	$ (2)	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ (1.35)	$ (1.26)	$ (4.30)
Diluted net earnings (loss) applicable to common stockholders per common share	$ 0.51	$ (0.10)	$ (0.10)	$ (2)	$ (0.32)	$ (0.22)	$ (0.39)	$ (0.33)	$ (0.14)	$ (3.67)	$ (0.29)	$ (0.19)	$ (1.35)	$ (1.26)	$ (4.30)