Brazos Valley Longhorn, L.L.C. 10-K 12 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	Feb. 28, 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	WRD
Entity Registrant Name	WildHorse Resource Development Corporation
Entity Central Index Key	1,681,714
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		101,304,079
Entity Public Float			$ 265.2

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 226	$ 3,115
Accounts receivable, net	84,103	26,428
Short-term derivative instruments	2,336	0
Prepaid expenses and other current assets	3,290	1,633
Total current assets	89,955	31,176
Property and equipment:
Oil and gas properties	2,999,728	1,573,848
Other property and equipment	53,003	34,344
Accumulated depreciation, depletion and amortization	(368,245)	(200,293)
Total property and equipment, net	2,684,486	1,407,899
Other noncurrent assets:
Restricted cash	0	886
Long-term derivative instruments	86	0
Debt issuance costs	3,573	2,320
Total assets	2,778,100	1,442,281
Current liabilities:
Accounts payable	53,005	21,014
Accrued liabilities	199,952	23,461
Short-term derivative instruments	58,074	14,087
Total current liabilities	311,031	58,562
Noncurrent liabilities:
Long-term debt	770,596	242,750
Asset retirement obligations	14,467	10,943
Deferred tax liabilities	71,470	112,552
Long-term derivative instruments	18,676	8,091
Other noncurrent liabilities	1,085	1,495
Total noncurrent liabilities	876,294	375,831
Total liabilities	1,187,325	434,393
Commitments and contingencies (Note 18)	0	0
Series A perpetual convertible preferred stock, $0.01 par value: 50,000,000 shares authorized; 435,000 shares issued and outstanding at December 31, 2017 (involuntary liquidation preference of $448,146)	445,483	0
Stockholders’ equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 101,137,277 shares and 91,680,441 shares issued and outstanding at December 31, 2017 and 2016, respectively	1,012	917
Additional paid-in capital	1,118,507	1,017,368
Accumulated earnings (deficit)	25,773	(10,397)
Total stockholders’ equity	1,145,292	1,007,888
Total liabilities and equity	$ 2,778,100	$ 1,442,281

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Convertible preferred stock, par value	$ 0.01	$ 0
Convertible preferred stock, shares authorized	50,000,000	0
Convertible preferred stock, shares issued	435,000	0
Convertible preferred stock, shares outstanding	435,000	0
Convertible preferred stock, involuntary liquidation preference	$ 448,146	$ 0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	101,137,277	91,680,441
Common stock, shares outstanding	101,137,277	91,680,441

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income:
Oil sales	$ 342,868	$ 75,938	$ 42,971
Natural gas sales	59,924	43,487	38,665
NGL sales	22,964	5,786	4,295
Other income	1,431	2,131	404
Total revenues and other income	427,187	127,342	86,335
Operating expenses:
Lease operating expenses	39,770	12,320	14,053
Gathering, processing and transportation	11,897	6,581	5,300
Taxes other than income tax	24,158	6,814	5,510
Depreciation, depletion and amortization	168,250	81,757	56,244
Impairment of proved oil and gas properties	0	0	9,312
General and administrative	40,663	23,973	15,903
Exploration expense	36,911	12,026	18,299
Other operating (income) expense	73	99	914
Total operating expense	321,722	143,570	125,535
Income (loss) from operations	105,465	(16,228)	(39,200)
Other income (expense):
Interest expense, net	(31,934)	(7,834)	(6,943)
Debt extinguishment gains (costs)	11	(1,667)	0
Gain (loss) on derivative instruments	(55,483)	(26,771)	13,854
North Louisiana settlement (Note 21)	(7,000)	0	0
Other income (expense)	(3)	(151)	(147)
Total other income (expense)	(94,409)	(36,423)	6,764
Income (loss) before income taxes	11,056	(52,651)	(32,436)
Income tax benefit (expense)	38,824	5,575	(604)
Net income (loss)	49,880	(47,076)	(33,040)
Net income (loss) attributable to previous owners	0	(2,681)	(3,085)
Net income (loss) attributable to predecessor	0	(33,998)	(29,955)
Net income (loss) available to WRD	49,880	(10,397)	0
Preferred stock dividends	13,146	0	0
Undistributed earnings allocated to participating securities	5,612	0	0
Net income (loss) available to common stockholders	$ 31,122	$ (10,397)	$ 0
Earnings per common share:
Basic	$ 0.32	$ (0.11)	$ 0
Diluted	$ 0.32	$ (0.11)	$ 0
Weighted-average common shares outstanding:
Basic	96,324	91,327	0
Diluted	96,324	91,327	0
Proved Properties
Operating expenses:
Impairment of proved oil and gas properties	$ 0	$ 0	$ 9,312

STATEMENTS OF CONSOLIDATED AND5

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 49,880	$ (47,076)	$ (33,040)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	167,537	81,350	55,890
Accretion of asset retirement obligations	713	407	354
Impairment of proved and unproved oil and gas properties	0	0	9,312
Dry hole expense	0	0	7,248
Amortization of debt issuance cost	2,575	479	711
Accretion of senior notes discount	342	0	0
(Gain) loss on derivative instruments	55,483	26,771	(13,854)
Cash settlements on derivative instruments	1,517	4,975	11,517
Deferred income tax expense (benefit)	(39,831)	(5,575)	604
Debt extinguishment expense	(11)	1,667	0
Amortization of equity awards	6,644	68	0
Gain (loss) on sale of properties	0	43	0
Changes in operating assets and liabilities
Decrease (increase) in accounts receivable	(56,828)	(16,300)	15,421
Decrease (increase) in prepaid expenses	(390)	(448)	165
Decrease (increase) in inventories	(648)	0	108
(Decrease) increase in accounts payable and accrued liabilities	69,555	(27,150)	(8,872)
Net cash flow provided by operating activities	277,372	22,262	50,096
Cash flows from investing activities:
Acquisitions of oil and gas properties	(551,242)	(436,072)	(165,836)
Additions to oil and gas properties	(700,546)	(125,837)	(253,922)
Additions to and acquisitions of other property and equipment	(15,959)	(5,403)	(23,653)
Sales of other property and equipment	0	102	22
Change in restricted cash	886	(335)	(250)
Net cash used in investing activities	(1,266,861)	(567,545)	(443,639)
Cash flows from financing activities:
Advances on revolving credit facilities	513,500	383,450	153,400
Payments on revolving credit facilities	(469,897)	(378,700)	(63,500)
Debt issuance cost	(15,279)	(3,607)	(875)
Termination of second lien	0	(225)	0
Proceeds from senior notes offering	494,744	0	0
Proceeds from the issuance of preferred stock	435,000	0	0
Proceeds from issuance of common stock	34,457	412,500	0
Repurchase of vested restricted stock	(564)	0	0
Previous owner and predecessor contributions	0	110,280	335,456
Net cash provided by financing activities	986,600	505,272	424,481
Net change in cash and cash equivalents	(2,889)	(40,011)	30,938
Cash and cash equivalents, beginning of period	3,115	43,126	12,188
Cash and cash equivalents, end of period	226	3,115	43,126
Common Stock
Cash flows from financing activities:
Costs incurred in conjunction with the issuance of preferred stock	(2,698)	(18,426)	0
Preferred Shares
Cash flows from financing activities:
Costs incurred in conjunction with the issuance of preferred stock	(2,663)	0	0
Proved Properties
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties	0	0	9,312
Unproved Properties
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties	$ 20,834	$ 3,051	$ 4,532

CONSOLIDATED AND COMBINED STATE

CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid in Capital	Accumulated Earnings (Deficit)
Beginning Balance (Predecessor) at Dec. 31, 2014	$ 178,991
Beginning Balance at Dec. 31, 2014	178,991
Balance at inception of common control (February 17, 2015) | Previous Owner	86,478
Balance at inception of common control (February 17, 2015)	86,478
Capital contributions | Predecessor	125,850
Capital contributions | Previous Owner	208,376
Capital contributions	334,226
Property contributions | Previous Owner	40,116
Property contributions	40,116
Common control step up in basis (Note 10) | Previous Owner	42,671
Common control step up in basis (Note 10)	42,671
Notes receivable from members, net | Predecessor	(753)
Notes receivable from members, net	(753)
Net income (loss) | Predecessor	(29,955)
Net income (loss) | Previous Owner	(3,085)
Net income (loss)	(33,040)
Ending Balance (Predecessor) at Dec. 31, 2015	274,133
Ending Balance (Previous Owner) at Dec. 31, 2015	374,556
Ending Balance at Dec. 31, 2015	648,689
Capital contributions | Predecessor	10,837
Capital contributions | Previous Owner	97,000
Capital contributions	107,837
Property contributions | Previous Owner	329
Property contributions	329
Issuance of common stock	412,500	$ 275	$ 412,225
Costs incurred in connection with the issuance of common stock	(19,252)		(19,252)
Notes receivable from members, net | Predecessor	(132)
Notes receivable from members, net	(132)
Dissolution of notes receivable from members | Predecessor	2,575
Dissolution of notes receivable from members	2,575
Amortization of equity awards	68	4	64
Issuance of shares in connection with Corporate Reorganization | Predecessor	(253,415)
Issuance of shares in connection with Corporate Reorganization | Previous Owner	(469,204)
Issuance of shares in connection with Corporate Reorganization		625	721,994
Issuance of common stock in connection with the Acquisition	19,626	13	19,613
Tax related effects in connection with Corporate Reorganization and initial public offering	(117,276)		(117,276)
Net income (loss) | Predecessor	(33,998)
Net income (loss) | Previous Owner	(2,681)
Net income (loss)	(47,076)			$ (10,397)
Ending Balance at Dec. 31, 2016	1,007,888	917	1,017,368	(10,397)
Issuance of common stock	34,457	23	34,434
Costs incurred in connection with the issuance of common stock	(1,872)		(1,872)
Deferred tax adjustment related to initial public offering	1,251		1,251
Accrual of preferred stock paid-in-kind dividend	(13,146)			(13,146)
Repurchase of vested restricted common stock	(564)			(564)
Amortization of equity awards	6,644	17	6,627
Issuance of common stock in connection with the Acquisition	60,754	55	60,699
Net income (loss)	49,880			49,880
Ending Balance at Dec. 31, 2017	$ 1,145,292	$ 1,012	$ 1,118,507	$ 25,773

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation WildHorse Resource Development Corporation (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “WRD,” or “the Company” are intended to mean the business and operations of WildHorse Resource Development Corporation and its consolidated subsidiaries. Reference to “WHR II” or our “predecessor” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries. Reference to “Esquisto I” refers to Esquisto Resources, LLC. Reference to “Esquisto II” refers to Esquisto Resources II, LLC. Reference to “Esquisto Merger” refers to the merger of Esquisto I with and into Esquisto II on January 12, 2016. Reference to “Esquisto” refers (i) for the period beginning February 17, 2015 (date of common control) through January 11, 2016, to Esquisto I and Esquisto II on a combined basis and (ii) for the period beginning January 12, 2016 through the completion of our initial public offering on December 19, 2016, to Esquisto II. Reference to “Acquisition Co.” refers to WHE AcqCo., LLC, an entity that was formed to acquire the Burleson North assets (see Note 3—Acquisitions and Divestitures). Reference to “WildHorse Investment Holdings” refers to WildHorse Investment Holdings, LLC. Reference to “Previous owner” refers to both Esquisto and Acquisition Co. Reference to “Esquisto Investment Holdings” refers to Esquisto Investment Holdings, LLC. Reference to “WildHorse Holdings” refers to WHR Holdings, LLC. Reference to “Esquisto Holdings” refers to Esquisto Holdings, LLC. Reference to “Acquisition Co. Holdings” refers to WHE AcqCo Holdings, LLC. Reference to “NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in WHR II, Esquisto and Acquisition Co. The Company was formed in August 2016 to serve as a holding company for the assets of WHR II and Esquisto. We did not have any operations until we completed our initial public offering on December 19, 2016. In connection with our initial public offering and Corporate Reorganization (defined below), our accounting predecessor, WHR II was contributed to us. In addition to WHR II, we received Esquisto and Acquisition Co. We are an independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Initial Public Offering and Corporate Reorganization The Company issued and sold to the public in its initial public offering 27,500,000 shares of common stock. The gross proceeds from the sale of the common stock were $412.5 million, net of underwriting discounts of $14.1 million and other offering costs of $5.0 million. The net proceeds from our initial public offering were $393.4 million. Debt issuance costs of $2.9 million related to the establishment of the Company’s revolving credit facility were also incurred in conjunction with our initial public offering. Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation. In May 2017, in connection with the Acquisition (see Note 3), WRD formed WHR Eagle Ford LLC (“WHR EF”) as a wholly owned subsidiary. In November 2017, WRD formed Burleson Sand LLC (“Burleson Sand”) in anticipation of an acquisition of land to develop a sand mine (see Note 21). WHR II has two wholly owned subsidiaries – WildHorse Resources Management Company, LLC (“WHRM”) and Oakfield Energy LLC (“Oakfield”). Esquisto has two wholly owned subsidiaries – Petromax E&P Burleson, LLC, and Burleson Water Resources, LLC (“Burleson Water”). WHRM is the named operator for all oil and natural gas properties owned by us. Basis of Presentation Our predecessor’s financial statements were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the financial statements included herein (i) (a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (ii) for the period from January 1, 2015 to February 16, 2015. Furthermore, the results of Acquisition Co. are reflected in the financial statements presented herein beginning on December 19, 2016. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Asset retirement obligations were previously separately presented on the consolidated balance sheets and is now being combined with Accrued liabilities on the consolidated balance sheets. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Subsequent Event. On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos Energy Holdings III, LLC (“Tanos”) for the sale of all of our producing and non-producing oil and natural gas properties, including Oakfield, primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”) for a total sales price of approximately $217.0 million (the “NLA Divestiture”), subject to customary purchase price adjustments. The NLA Assets consist of all of our assets in our North Louisiana Acreage. In addition, WRD could receive contingent payments of up to $35.0 million based on the number of wells spud on such properties over the next four years. The effective date of the proposed sale is January 1, 2018, and we expect to close the transaction by the end of March 2018. The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the Purchase and Sale Agreement, Tanos paid WHR II a deposit of $21.7 million at signing, which amount will be applied to the sales price if the transaction closes. The completion of the NLA Divestiture is subject to customary closing conditions. The parties may terminate the Purchase and Sale Agreement by mutual written consent or if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or approximately $43 million, or the transaction has not closed on or before April 30, 2018. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the NLA Assets on the terms or timing described or at all. If the NLA Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our revolving credit facility and for general corporate purposes. Due to asset held-for-sale guidance, we anticipate recording an impairment loss on the NLA Assets during the first quarter of 2018. The net book value of the NLA assets was $415.0 million at December 31, 2017.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies Use of Estimates in the Preparation of Financial Statements Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (6) deferred taxes; (7) environmental remediation costs; (8) valuation of derivative instruments; (9) contingent liabilities; and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material. Cash and Cash Equivalents We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the Consolidated and Combined Statements of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable. Restricted Cash Restricted cash consists of certificates of deposit in place to collateralize letters of credit. The letters of credit are required as part of normal business operations. The certificates of deposit will be in place for a period greater than 12 months and are considered noncurrent. Oil and Gas Properties We use the successful efforts method of accounting for crude oil and natural gas producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Costs to drill and develop development wells and costs to drill and develop exploratory wells that find proved reserves are also capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed. The following table reflects the net changes in capitalized exploratory well costs for the periods indicated: For Year Ended December 31, 2017 2016 2015 Balance, beginning of period $ 7,064 $ 15,198 $ 11,134 Balance at inception of common control — — 6,385 Additions to capitalized exploratory well costs pending the determination of proved reserves — 60,847 96,726 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (7,064 ) (68,981 ) (93,052 ) Capitalized exploratory well costs charged to expense — — (5,995 ) Balance, end of period $ — $ 7,064 $ 15,198 We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable. We recorded impairment of $20.8 million, $3.1 million and $1.2 million as exploration expense for unproved oil and gas properties for the years ended December 31, 2017, 2016 and 2015, respectively. Our previous owner recorded impairment of $3.3 million as exploration expense for unproved oil and gas properties for the year ended December 31, 2015. Capitalized costs of producing crude oil and natural gas properties and support equipment, net of estimated salvage values, are depleted by field using the units-of-production method. Well and well equipment and tangible property additions are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. We did not record any impairment expense to proved oil and gas properties for the year ended December 31, 2017 and 2016. We recorded impairment expense of $9.3 million to proved oil and gas properties for the year ended December 31, 2015. The impairment resulted from lower projected oil and gas prices and a drop in projected remaining reserves in non-core fields. Oil and Gas Reserves The estimates of proved crude oil, natural gas, and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Our proved reserves are prepared by us and audited by Cawley, Gillespie & Associates, Inc. (“Cawley”), our independent reserve engineer. Proved reserves for 2016 were, with respect to WHR II, prepared by WHR II and audited by Cawley. With respect to Esquisto, the proved reserves were prepared by Cawley, its independent reserve engineer, for 2015. Esquisto’s proved reserves for 2016 were internally prepared and audited by Cawley. We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 20—“Supplemental Oil and Gas Information (Unaudited)” for further information. Other Property and Equipment Other property and equipment includes our natural gas gathering system, Burleson water assets, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized. Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2017, 2016 and 2015, we recorded $ 3.1 million, $0.1 million and $0.8 million in capitalized interest, respectively. Properties Acquired in Asset Acquisitions and Business Combinations Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions and Divestitures.” Asset Retirement Obligations We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production method of the related asset. The accretion expense is included in depreciation, depletion and amortization expense. The fair value of the estimated cost is based on historical experience, managements’ expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated plug and abandonment expense, changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. Environmental Costs As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Revenue Recognition and Oil and Gas Imbalances Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. We receive payment approximately one month after delivery for operated crude oil wells, approximately two months after delivery for operated natural gas wells and up to three months after delivery for non-operated wells. Regarding hedge revenue, hedge settlements occur in the same month for natural gas and in the month following for crude oil. Hedge revenue is recorded as a component of “Other income (expense)” on our Statement of Consolidated and Combined Operations. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received. Incentive Units For details regarding incentive units issued by our predecessor, please see “Note 14. Incentive Units.” Accounts Receivable We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of crude oil, natural gas and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties. Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes one month of accrued revenues for operated oil properties, two months of accrued revenues for operated natural gas properties and three months of accrued revenues for non-operated properties net of any collections related to those periods. The accounts receivable balance also includes other miscellaneous balances. Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.1 million at both December 31, 2017 and 2016. Derivative Instruments We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price commodity swaps, basis swaps, collars and deferred purchased puts. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales. All derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. Changes in fair value are recognized currently in earnings. Realized and unrealized gains and losses from our oil, gas and natural gas liquids derivatives are recorded as a component of “Other income (expense)” on our Statements of Consolidated and Combined Operations. We compute the fair value of the unrealized gains and losses of our derivative instruments using forward prices and dealer quotes provided by a third party. See Note 5—“Risk Management and Derivative and Other Financial Instruments” for additional information regarding our derivative instruments. Corporate Lease Expenses We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis. Debt Issuance Costs Debt issuance costs associated with line-of-credit arrangements, including arrangements with no outstanding borrowings, are classified as an asset, and amortized over the term of the arrangements. Debt issuance costs related to term loans and senior notes are presented as a direct deduction from the carrying amount of the associated debt liability and amortized over the term of the associated debt using the effective yield method. Fair Value Measurements Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements of Financial Instruments.” Income Taxes We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carry forwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. Commitments and Contingencies Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Supplemental Cash Flow Information Supplement cash flow for the periods presented: For Year Ended December 31, 2017 2016 2015 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 12,246 $ 7,152 $ 7,253 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities 134,589 (4,492 ) 349 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (847 ) (5,175 ) — Due to Hurricane Harvey, the Internal Revenue Service (“IRS”) granted relief to affected taxpayers by allowing taxpayers to defer the deadline for tax return filings and payment of estimated taxes to January 31, 2018. The Company paid $2.3 million related to its 2017 estimated alternative minimum tax to the IRS on January 31, 2018. New Accounting Standards Definition of a Business. In January 2017, the FASB issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption was permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption was permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the Leases. In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the required modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standard will extend over future periods. Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step model to analyze contracts to determine when and how revenue is recognized. Central to the five-step model is the concept of control and the timing of the transfer of that control determines the timing of when revenue can be recognized. Control as defined in the standard is the “ability to direct the use of, and obtain substantially all of the remaining benefits from, the asset.” The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 and permits the use of either the full retrospective or cumulative effect transition method. The Company adopted this new standard on January 1, 2018, using the cumulative effect transition method. The cumulative effect transition method requires entities to apply the new standard by recording a cumulative effect adjustment to the opening balance of accumulated earnings based on the impact of applying the standard to contracts that were not completed as of January 1, 2018. The adoption of the new revenue recognition standard does not materially impact the financial position or the results of the operations of the Company; however, two primary differences for our natural gas processing and purchasing contracts are discussed below. Our oil sales contracts are not impacted by the new standard. • First, certain of our contracts require us to make up-front payments to our customers to reimburse them for the cost of installing metering and custody transfer equipment or constructing pipelines from our wells to their facilities. Instead of capitalizing these payments to our Oil and Gas Properties and depleting them, they will be amortized over the period of the benefit and be presented as a reduction to revenue. The difference in accounting will be recognized as an immaterial cumulative effect adjustment to opening accumulated earnings. • Second, the fees we are assessed on certain of our gas processing and purchasing contracts must be reclassified from gathering, processing and transportation expense to revenue. The standard requires these amounts to be a revenue deduction because control of our natural gas under these contracts transfers to our customers prior to the provision of any services by our customers. This difference in presentation of fees will have no impact on our financial position or the results of the operations of the Company. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on our consolidated financial statements and footnote disclosures.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures We account for third-party acquisitions under the acquisition method. The assets acquired and the liabilities assumed have been measured at fair value based on various estimates. These estimates are based on key assumptions related to the business combination, including reviews of publicly disclosed information for other acquisitions in the industry, historical experience of the companies, data that was available through the public domain and due diligence reviews of the acquired businesses. Acquisition-related transaction costs and acquisition-related restructuring charges are not included as components of consideration transferred but are accounted for as expenses in the period in which the costs are incurred. Acquisition-related costs Acquisition-related costs for both related party and third-party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Year Ended December 31, 2017 2016 2015 $ 4,348 $ 553 $ 593 2017 Acquisitions The Acquisition. On May 10, 2017, we, through our wholly owned subsidiary, WHR EF, entered into a Purchase and Sale Agreement (the “First Acquisition Agreement”) by and among WHR EF, as purchaser, and APC and KKR (together with APC, the “First Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas (the “Purchase”). Also on May 10, 2017, WHR EF entered into a Purchase and Sale Agreement (together, with the First Acquisition Agreement, the “Acquisition Agreements”), by and among WHR EF, as purchaser, and APC and Anadarko Energy Services Company (together, with APC, the “APC Subs” and, together with the First Sellers, the “Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas (together, with the Purchase, the “Acquisition”). O n June 30, 2017, we completed the Acquisition. The aggregate purchase price for the Acquisition, as described in the Acquisition Agreements, consisted of an aggregate of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (collectively, the “Adjusted Purchase Price”). The common stock portion of the Adjusted Purchase Price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017, by and among us and KKR. For the year ended December 31, 2017, revenues of $42.6 million were recorded in the statement of operations, which generated $11.1 million of income subsequent to the closing date. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing of the Acquisition (in thousands): Consideration : Cash $ 533,609 Common stock 60,754 Total consideration $ 594,363 Preliminary Purchase Price Allocation: Proved oil and gas properties $ 264,144 Unproved oil and gas properties 333,778 Accounts receivable 967 Asset retirement obligations (2,500 ) Accrued liabilities (2,026 ) Total identifiable net assets $ 594,363 Supplemental Pro forma Information. The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2017 and 2016 as though the Acquisition had been completed on January 1, 2016 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the Acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Year Ended December 31, 2017 2016 Revenues $ 475,396 $ 226,502 Net income (loss) 71,287 (11,290 ) Earnings per share (basic and diluted) $ 0.51 $ (0.10 ) Burleson 2017 Acquisitions. During the year ended December 31, 2017, we closed on multiple transactions to acquire oil and natural gas producing and non-producing properties from third parties in Burleson County, Texas for approximately $19.7 million, of which $11.6 million was allocated to unproved oil and natural gas properties. 2016 Acquisitions Burleson North Acquisition . On December 19, 2016, in connection with our initial public offering, we completed an acquisition of approximately 158,000 net acres of oil and natural gas properties adjacent to our existing Eagle Ford acreage (the “Burleson North Acquisition”). Funds wired on December 19, 2016 were $389.8 million. During the three months ended March 31, 2017, we received a post-closing receipt of $3.9 million. We allocated $162.9 million of the purchase price to unproved oil and natural gas properties. For the year ended December 31, 2016, revenues of $2.0 million were recorded in the statement of operations and generated a loss of approximately $0.4 million subsequent to the closing date. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands): Purchase Price Oil and gas properties $ 395,591 Other property and equipment 478 Accounts receivable 1,257 Accounts payable (1,816 ) Asset retirement obligations (3,101 ) Accrued liabilities (6,503 ) Total identifiable net assets $ 385,906 Rosewood Acquisition. On December 19, 2016, we acquired from certain third parties approximately 7,500 net acres, consisting primarily of additional working interests in our Eagle Ford Acreage in Lee County (the “Rosewood Acquisition”). The closing of the acquisition occurred contemporaneously with the closing of our initial public offering, and we issued 1,308,427 shares to such third parties as consideration. We allocated $18.3 million of the purchase price to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties. November Acquisition. On November 8, 2016, Esquisto acquired from certain third parties approximately 4,900 net acres and nine producing wells in Burleson County for approximately $30.0 million (the “November Acquisition”), of which $29.4 million of the purchase price was allocated to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties . The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date for the November Acquisition and Rosewood Acquisition (in thousands): Rosewood Acquisition November Acquisition Oil and gas properties 19,626 29,973 The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 and 2015 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company, the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Year Ended December 31, 2016 2015 Revenues $ 176,082 $ 172,044 Net income (loss) (34,894 ) (83,894 ) Basic and diluted earnings per unit n/a n/a 2015 Acquisitions Comstock Acquisition . In July 2015, Esquisto acquired oil and natural gas producing properties, undeveloped acreage and water assets from a wholly owned subsidiary of Comstock Resources, Inc. for a total purchase price of $103.0 million, net of customary post-closing adjustments. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Comstock Acquisition Oil and gas properties $ 102,628 Other property and equipment 500 Asset retirement obligations (112 ) Total identifiable net assets $ 103,016

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2017 and 2016, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity). Assets and Liabilities Measured at Fair Value on a Recurring Basis The carrying values of cash and cash equivalents, restricted cash, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2017 and December 31, 2016. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2017 and December 31, 2016 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2017 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 2,422 $ — $ 2,422 Liabilities: Commodity derivatives $ — $ 76,750 $ — $ 76,750 Fair Value Measurements at December 31, 2016 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 7 $ — $ 7 Liabilities: Commodity derivatives $ — $ 22,185 $ — $ 22,185 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: • The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 8 for a summary of changes in AROs. • If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach. • Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. During the year ended December 31, 2015, we recognized $9.3 million of impairments on proved properties. The impairments primarily related to certain properties located in East Texas and our non-core fields. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to declining commodity prices. We did not record impairments on proved properties for the year ended December 31, 2017 and 2016.

Risk Management and Derivative

Risk Management and Derivative and Other Financial Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments and Other Financial Instruments	Note 5. Risk Management and Derivative and Other Financial Instruments We have entered into certain derivative arrangements with respect to portions of our oil and natural gas production to reduce our sensitivity to volatile commodity prices. None of our derivative instruments are designated as cash flow hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve more predictable cash flows and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil and natural gas sales. Moreover, our derivative arrangements apply only to a portion of our production and provide only partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our risk management program in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements. Commodity Derivatives We have fixed price commodity swaps, basis swaps, collars and deferred purchased puts to accomplish our hedging strategy. Through our basis swap instruments, we receive a fixed price differential and pay a variable price differential to the contract counterparty. Collars consist of a sold call and a purchased put that establish a ceiling and floor price for expected future oil and natural gas sales. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and where the Company agrees to defer the premium paid or received until the time of settlement. Cash received on settled derivative positions during the year ended December 31, 2017 is net of deferred premiums of $6.3 million. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, certain of which are also lenders under the Credit Agreement, which could expose us to credit risk in the event of default of our counterparties. We have master netting agreements for our derivative transactions with our counterparties and although we do not require collateral, we believe our counterparty risk is low because of the credit worthiness of our counterparties. Master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments by providing us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative or other financial instrument, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative and other financial asset receivables from the defaulting party. At December 31, 2017 we had net derivative liabilities of $74.3 million and did not have a right of offset as we were in a net liability position with all of our counterparties. The following derivative contracts were in place at December 31, 2017: 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 6,834,488 4,537,693 1,101,762 Weighted-average fixed price $ 52.31 $ 52.69 $ 50.19 Collar contracts: Volume (Bbls) 25,096 — — Weighted-average floor price $ 50.00 $ — $ — Weighted-average ceiling price $ 62.10 $ — $ — Put options: Volume (Bbls) 2,666,836 410,525 — Weighted-average floor price $ 51.74 $ 50.00 $ — Weighted-average put premium $ (3.47 ) $ (5.95 ) $ — LLS basis swaps: Volume (Bbls) 3,728,700 — — Spread-WTI $ 3.04 $ — $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 11,825,800 9,877,900 — Weighted-average fixed price $ 3.03 $ 2.81 $ — All of our existing natural gas derivative contracts will be novated to Tanos in connection with the closing of the NLA Divestiture. Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2017 and 2016. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2017 2016 2017 2016 Commodity contracts Short-term derivative instruments $ 2,336 $ 4 $ 58,074 $ 14,091 Netting arrangements Short-term derivative instruments — (4 ) — (4 ) Net recorded fair value $ 2,336 $ — $ 58,074 $ 14,087 Commodity contacts Long-term derivative instruments $ 86 $ 3 $ 18,676 $ 8,094 Netting arrangements Long-term derivative instruments — (3 ) — (3 ) Net recorded fair value $ 86 $ — $ 18,676 $ 8,091 Gains & (Losses) on Derivatives All gains and losses, including changes in the derivative instruments’ fair values, are included as a component of “Other income (expense)” in the Statements of Combined and Consolidated Financial Statements. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2017, 2016 and 2015: Statements of For the Year Ended December 31, Operations Location 2017 2016 2015 Commodity derivative contracts Gain (loss) on commodity derivatives $ (55,483 ) $ (26,771 ) $ 13,854

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2017
Receivables [Abstract]
Accounts Receivable	Note 6. Accounts Receivable Accounts receivable consist of the following: At December 31, 2017 2016 Oil, gas and NGL sales $ 67,584 $ 13,390 Joint interest billings 9,467 7,898 Severance tax 171 392 North Louisiana Settlement receivable (Note 21) 5,955 — Other current receivables (1) 1,026 4,848 Allowance for doubtful accounts (100 ) (100 ) Total $ 84,103 $ 26,428 (1) At December 31, 2016, primarily relates to a receivable related to our North Burleson Acquisition. The following table presents our allowance for doubtful accounts activity for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Balance at beginning of period $ 100 $ 50 $ — Charged to costs and expenses — 50 50 Balance at end of period $ 100 $ 100 $ 50

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2017
Payables And Accruals [Abstract]
Accrued Liabilities	Note 7. Accrued Liabilities Accrued liabilities consist of the following: At December 31, 2017 2016 Capital expenditures $ 162,260 $ 17,934 Deferred rent 410 386 Lease operating expense 5,796 2,608 General and administrative 1,642 1,471 Severance and ad valorem taxes 3,463 194 Interest expense 17,177 346 Derivative payable 5,281 428 Income taxes 991 — Other accrued liabilities 2,932 94 Total $ 199,952 $ 23,461

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 8. Asset Retirement Obligations The following table presents the changes in the asset retirement obligations for the year ended December 31, 2017, 2016 and 2015: For the Year Ended December 31, 2017 2016 2015 Asset retirement obligations at beginning of period $ 11,033 $ 7,020 $ 5,935 Balance at inception of common control (February 17, 2015) — — 37 Accretion expense 713 407 354 Liabilities incurred 3,137 3,723 686 Liabilities settled — (5 ) (8 ) Revisions (326 ) (112 ) 16 Asset retirement obligations at end of period 14,557 11,033 7,020 Less: current portion 90 90 90 Asset retirement obligations – long-term $ 14,467 $ 10,943 $ 6,930

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long Term Debt	Note 9. Long Term Debt Our debt obligations consisted of the following at the dates indicated: For the Year Ended December 31, Debt Obligation 2017 2016 WRD revolving credit facility $ 286,353 $ 242,750 2025 Senior Notes (as defined below) (1) 500,000 — Unamortized discounts - 2025 Senior Notes (4,914 ) — Unamortized debt issuance costs - 2025 Senior Notes (10,843 ) — Total long-term debt $ 770,596 $ 242,750 (1) The estimated fair value of this fixed-rate debt was $511.3 million at December 31 2017. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. Borrowing Base Credit facilities tied to borrowing base are common throughout the oil and natural gas industry. Our borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for our revolving credit facility was the following at the date indicated (in thousands): December 31, Credit Facility 2017 WRD revolving credit facility $ 875,000 Revolving Credit Facility On December 19, 2016 after the closing of our initial public offering, we, as borrower, and certain of our current and future subsidiaries, as guarantors, entered into a five-year, $1.0 billion senior secured revolving credit facility, which had an initial borrowing base of $450.0 million but was automatically reduced to $362.5 million in connection with the consummation of our 2025 Senior Notes (defined below) offering on February 1, 2017. On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a Second Amendment to the Credit Agreement (the “Second Amendment”) dated as of December 19, 2016, among the Company, the Administrative Agent and the other agents and lenders party thereto (as amended, the “Credit Agreement”). The Second Amendment, among other things, modified the Credit Agreement to (i) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock (see Note 10), (ii) increase the Company’s borrowing base and elected commitment amount from $450 million to $650 million, (iii) increase the annual cap on certain restricted payments from $50 million to $75 million, and (iv) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified capital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company’s leverage covenant. On October 4, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into a Third Amendment to the Credit Agreement (the “Third Amendment”). The Third Amendment, among other things, modified the Credit Agreement to (i) increase the aggregate maximum credit amount to $2.0 billion from $1.0 billion, (ii) increase the borrowing base from $612.5 million to $875.0 million and (iii) add additional lenders. Our revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion consistent with their normal and customary oil and gas lending practices semi-annually (in the case of scheduled redeterminations), from time to time at our election in connection with material acquisitions, or no more frequently than twice in any fiscal year at the request of the required lenders or us (in the case of interim redeterminations), in each case based on engineering reports with respect to our estimated oil, NGL and natural gas reserves, and our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base pursuant to a redetermination, while only required lender approval is required to maintain or decrease the borrowing base pursuant to a redetermination. The borrowing base will also automatically decrease upon the issuance of certain debt, including notes, the sale or other disposition of certain assets and the early termination of certain swap agreements. In the future, we may be unable to access sufficient capital under the Credit Agreement as a result of (i) a decrease in our borrowing base due to a borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations. A decline in commodity prices could result in a redetermination that lowers our borrowing base and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Agreement. Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 85% (or 75% with respect to certain properties prior to February 2, 2017) of the total value, as determined by the administrative agent, of the proved reserves attributable to our oil and natural gas properties using a discount rate of 9%, all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property but excluding equity interests in and assets of unrestricted subsidiaries. Additionally, borrowings under our revolving credit facility will bear interest, at our option, at either: (i) the Alternate Base Rate, which is based on the greatest of (x) the prime rate as determined by the Administrative Agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies from 1.00% to 2.00% per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies from 2.00% to 3.00% per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.00% to 3.00% per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage. The Credit Agreement requires us to maintain (x) a ratio of total debt to EBITDAX (as defined under our revolving credit facility) of not more than 4.00 to 1.00 and (y) a ratio of current assets (including availability under the facility) to current liabilities of not less than 1.00 to 1.00. Additionally, the Credit Agreement contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness. Events of default under the Credit Agreement will include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond any applicable cure period, default under any other material debt, change of control, bankruptcy or other insolvency event and certain material adverse effects on our business. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, fees and other obligations under the Credit Agreement, could be declared immediately due and payable. WHR II Revolving Credit Facility We repaid and terminated WHR II’s prior revolving credit facility in connection with the completion of our initial public offering. Esquisto Revolving Credit Facility We repaid and terminated Esquisto’s prior revolving credit facility in connection with the completion of our initial public offering. Esquisto Terminated Revolving Credit Facility and Second Lien Loan. Esquisto retired and terminated one of their revolving credit facilities and second lien loan in January 2016 in connection with the merger of Esquisto I and Esquisto II. 2025 Senior Notes On February 1, 2017, we completed a private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $338.6 million. In addition, on September 19, 2017, we completed another private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par, which resulted in net proceeds of approximately $144.7 million. The notes issued in September 2017 are treated as a single class of debt securities with the 2025 Senior Notes issued in February 2017. The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year. The 2025 Senior Notes are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions). We have no material assets or operations that are independent of our existing subsidiaries. There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans. The net proceeds from each of the offerings of the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes. Pursuant to the registration rights agreements entered into in connection with the offerings of the 2025 Senior Notes, we agreed to file a registration statement with the SEC so that holders of the 2025 Senior Notes could exchange the unregistered 2025 Senior Notes for registered notes with substantially identical terms. In addition, we agreed to exchange the unregistered guarantees related to the 2025 Senior Notes for registered guarantees with substantially identical terms. On November 20, 2017, substantially all of the outstanding 2025 Senior Notes were exchanged for an equal principal amount of registered 6.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4. We may redeem all or any part of the 2025 Senior Notes at a “make-whole” redemption price, plus accrued and unpaid interest, at any time before February 1, 2020. We may also redeem up to 35% of the aggregate principal amount of the 2025 Senior Notes prior to February 1, 2020 in an amount not greater than the net cash proceeds from one or more equity offerings at a redemption price of 106.875% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: For the Year Ended December 31, Credit Facility 2017 2016 2015 WRD revolving credit facility 3.60 % 3.52 % n/a WHR II revolving credit facility terminated December 2016 n/a 3.03 % 2.60 % Esquisto - revolving credit facility terminated December 2016 n/a 2.84 % 3.13 % Esquisto - revolving credit facility terminated January 2016 n/a 2.97 % 2.97 % Esquisto - Second lien terminated in January 2016 n/a 9.50 % 9.25 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated (dollars in thousands): At December 31, 2017 2016 WRD revolving credit facility Current $ 1,203 $ 584 Long-term 3,573 2,320 6.875% senior unsecured notes, due February 2025 10,843 n/a $ 15,619 $ 2,904

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2017
Temporary Equity [Abstract]
Preferred Stock	Note 10. Preferred Stock Preferred Stock Issuance We partially funded the Acquisition through the issuance of 435,000 shares of Preferred Stock in exchange for $435.0 million on June 30, 2017, pursuant to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P. Series A Perpetual Convertible Preferred Stock (in thousands) Balance at December 31, 2016 $ — Issuance of preferred stock in connection with the Acquisition 435,000 Costs incurred related to the issuance of preferred stock (2,663 ) Accrual of preferred stock paid-in-kind dividend 13,146 Balance at December 31, 2017 $ 445,483 The Preferred Stock ranks senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock had an initial Accreted Value (as defined in the Certificate of Designations 6.00% Series A Perpetual Convertible Preferred Stock (the “Certificate”)) of $1,000 per share and is entitled to a dividend at a rate of 6% per annum on the Accreted Value payable in cash if, as and when declared by our board of directors. If a cash dividend is not declared and paid in respect of any dividend payment period, then the Accreted Value of each outstanding share of Preferred Stock will automatically be increased by the amount of the dividend otherwise payable for such dividend payment period. Any increase in the Accreted Value, among other things, increases the number of shares of common stock issuable upon conversion of each share of Preferred Stock. With respect to each of the quarterly periods since issuance, our board of directors has elected to pay the dividend on the preferred stock by increasing the Accreted Value rather than paying cash. As such, as of January 31, 2018, the Accreted Value was $1,024 per share. The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently. The Preferred Stock is convertible at the option of the holders at any time after June 30, 2018 into the amount of shares of common stock per share of Preferred Stock (such rate, the “Conversion Rate”) equal to the quotient of (i) the Accreted Value in effect on the conversion date divided by (ii) a conversion price of $13.90 (the “Conversion Price”), subject to customary anti-dilution adjustments and customary provisions related to partial dividend periods. The holders of Preferred Stock may also convert their Preferred Stock at the Conversion Rate prior to June 30, 2018 in connection with certain change of control transactions and in connection with sales of common stock by certain of our existing stockholders. Following June 30, 2021, the Company may cause the conversion of the Preferred Stock at the Conversion Rate, provided the closing sale price of the common stock equals or exceeds 140% of the Conversion Price for the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert and subject to certain other requirements regarding registration of the shares issuable upon conversion. Notwithstanding the foregoing, the Company shall only be permitted to deliver one conversion notice during any 180-day period and the number of shares of common stock issued upon conversion of the Preferred Stock for which such automatic conversion notice is given shall be limited to 25 times the average daily trading volume of our common stock during the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert. If the Company undergoes certain change of control transactions, the holders of the Preferred Stock are entitled to cause the Company to redeem the Preferred Stock for cash in an amount equal to the Accreted Value, plus the net present value of dividend payments that would have been accrued as payable to the holders following the date of the consummation of such change of control and through December 30, 2019, in the case of any change of control occurring prior to December 30, 2019 (the “COC Redemption Price”). In addition, the Company has the right in connection with any such change of control transaction (i) to elect to redeem any Preferred Stock contingent upon and contemporaneously with the consummation of such change of control or (ii) to redeem any Preferred Stock following the consummation of such control that is not otherwise converted or redeemed as described in the preceding sentence and clause (i) of this sentence for cash at the COC Redemption Price. At any time after June 30, 2022, the Company may redeem the Preferred Stock, in whole or in part, for an amount in cash equal to, per each share of Preferred Stock, (i) on or prior to the June 30, 2023, the Accreted Value multiplied by 112%, (ii) on or prior to June 30, 2024, the Accreted Value multiplied by 109% or (ii) after June 30, 2024, the Accreted Value multiplied by 106%. Until conversion, the holders of the Preferred Stock vote together with our common stock on an as-converted basis and also have rights to vote as a separate class on certain customary matters impacting the Preferred Stock. In addition, the Carlyle Investor, as a holder of Preferred Stock is entitled to elect (i) two directors to our board of directors for so long as the Carlyle Investor or its affiliates hold Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing at least 10% of our outstanding common stock on an as-converted basis and (ii) one board seat for so long as the Carlyle Investor or its affiliates hold Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing 5% or more of our outstanding common stock on an as-converted basis. Preferred Stock Dividend – Payment In Kind On July 31, 2017, we announced an aggregate quarterly dividend of $2.175 million on our outstanding shares of Preferred Stock. The dividend was paid by an automatic increase to the Accreted Value of each such share of Preferred Stock, which were issued with an initial Accreted Value of $1,000 per share. The dividend was for the period beginning on June 30, 2017 (the issuance date of the Preferred Stock) to July 31, 2017 and was paid to holders of record on July 15, 2017. On October 31, 2017, an aggregate quarterly dividend of $6.558 million was paid by an automatic increase to the Accreted Value of each such share of Preferred Stock as of the date of issuance. The declared dividend is for the period beginning on August 1, 2017 to October 31, 2017 and was paid to holders of record on October 15, 2017. Subsequent event. On January 31, 2018, an aggregate quarterly dividend of $6.656 million was paid by an automatic increase to the Accreted Value of each such share of Preferred Stock as of the date of issuance. The declared dividend is for the period beginning on November 1, 2017 to January 31, 2018 and was paid to holders of record on January 15, 2018. In connection with this paid-in-kind dividend, we recognized a $1.9 million beneficial conversion feature that will be amortized over the earliest Preferred Stock conversion period as additional dividends.

Equity

Equity	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Equity	Note 11. Equity Common Stock The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued since January 1, 2016: Balance, January 1, 2016 (1) — Shares of common stock issued in connection with Corporate Reorganization 62,518,680 Shares of common stock issued in initial public offering 27,500,000 Shares of common stock issued in connection with Rosewood Acquisition 1,308,427 Restricted common shares issued 353,334 Balance, December 31, 2016 91,680,441 Common stock issued 7,815,225 Restricted common shares issued 1,676,284 Restricted common shares forfeited (717 ) Repurchase of vested restricted shares (2) (33,956 ) Balance, December 31, 2017 101,137,277 (1) We were incorporated in August 2016 under the laws of the State of Delaware. (2) Restricted common shares are generally net-settled by 2016 LTIP participants to cover the required withholding tax upon vesting of restricted stock awards. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $0.6 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company. In January 17, 2017, we issued and sold 2,297,100 shares of our common stock at an offering price of $15.00 per share pursuant to the partial exercise of the underwriters’ over-allotment option associated with our initial public offering the (“Option Exercise”). We received net proceeds of $32.6 million from the Option Exercise, all of which was used to repay outstanding borrowings under our revolving credit facility. On June 30, 2017, pursuant to the Acquisition Agreements, we issued 5,518,125 shares of our common stock valued at approximately $60.8 million as partial consideration to KKR. See Note 3 for additional information regarding the Acquisition. See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted during the year ended December 31, 2017. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award. Dividend Policy We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, the Credit Agreement places restrictions on our ability to pay cash dividends. Predecessor Equity The predecessor received capital contributions of $10.8 million and $125.9 million from its members during the year ended December 31, 2016 and 2015, respectively. Promissory note advances were available to management to fund future capital commitments and carried an interest rate of 2.5%. The table below summarizes advances and payments of the promissory note advances for the years ended December 31, 2016 and 2015: Principal Interest Total Balance, December 31, 2014 $ 1,651 $ 39 $ 1,690 Advances 1,096 — 1,096 Payments (380 ) (13 ) (393 ) Accrued Interest — 50 50 Balance, December 31, 2015 2,367 76 2,443 Advances 101 — 101 Payments (20 ) — (20 ) Accrued Interest — 51 51 Dissolution (2,448 ) (127 ) (2,575 ) Balance, December 31, 2016 $ — $ — $ — On November, 9, 2016, the management members conveyed to the predecessor certain ownership interests in the predecessor in exchange for the discharge in full and the termination of all the promissory note advances then outstanding. The promissory note advances and the related accrued interest receivable are presented in the balance sheet as a deduction from predecessor equity. Previous Owner Equity The previous owner received capital contributions of $97.0 million and $208.4 million from its members during the year ended December 31, 2016 and for the period of February 17, 2015 to December 31, 2015, respectively. During the period from February 17, 2015 to December 31, 2015, Esquisto received property contributions of $40.1 million from its members that primarily consisted of developed and undeveloped properties in the East Texas Eagle Ford, Austin Chalk and Pecan Gap formations in Lee County, Washington County and Brazos County, Texas. On February 17, 2015, NGP acquired a controlling interest in Esquisto from an Esquisto member not affiliated with NGP. NGP’s basis exceeded the net book value by $16.1 million associated with this

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	Note 12. Earnings per share The following sets forth the calculation of earnings (loss) per share, or EPS, for the year ended December 31, 2017 and 2016 (in thousands, except per share amounts). In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. For the Year Ended December 31, 2017 2016 Numerator: Net income (loss) available to WRD $ 49,880 $ (10,397 ) Less: Preferred stock dividends 13,146 — Less: Undistributed earnings allocated to participating securities 5,612 — Net income (loss) available to common stockholders $ 31,122 $ (10,397 ) Denominator: Weighted-average common shares outstanding (in thousands) (1) 96,324 91,327 Basic EPS $ 0.32 $ (0.11 ) Diluted EPS (1) $ 0.32 $ (0.11 ) (1) The Company used the two-class method for both basic and diluted EPS. For the twelve months ended December 31, 2017, 628 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the twelve months ended December 31, 2017, 16,008 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

Long Term Incentive Plans

Long Term Incentive Plans	12 Months Ended
	Dec. 31, 2017
Long Term Incentive Plans
Long Term Incentive Plans	Note 13. Long Term Incentive Plans In connection with the initial public offering, our Board adopted the 2016 Long-Term Incentive Plan (or “2016 LTIP”). The 2016 LTIP, authorizes the issuance of 9,512,500 shares of our common stock. The following table summarizes information regarding restricted common share awards granted under the 2016 LTIP for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at January 1, 2016 — $ — Granted (2) 353,334 $ 14.50 Restricted common shares outstanding at December 31, 2016 353,334 $ 14.50 Granted (2) 1,676,284 $ 13.88 Forfeited (717 ) $ 13.94 Vested (131,111 ) $ 14.50 Restricted common shares outstanding at December 31, 2017 1,897,790 $ 13.95 (1) Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common share awards granted in 2016 was $5.1 million based on grant date market price of $14.50 per share. The aggregate grant date fair value of restricted common share awards granted in 2017 was $23.3 million based on grant date market price ranging from $10.91 to $14.22 per share. For the year ended December 31, 2017 and 2016, we recorded $6.6 million and $0.1 million of recognized compensation expense associated, respectively, with these awards. Unrecognized compensation cost associated with the restricted common share awards was an aggregate of $21.7 million at December 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.34 years.

Incentive Units

Incentive Units	12 Months Ended
	Dec. 31, 2017
Compensation Related Costs [Abstract]
Incentive Units	Note 14. Incentive Units The governing documents of WHR II provided for the issuance of incentive units. WHR II granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units would have been entitled to distributions ranging from 20% to 40% when declared, but only after cumulative distribution thresholds (payouts) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. The incentive units were being accounted for as liability-classified awards as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. The payment likelihood related to the WHR II incentive units was not deemed probable for the years ended December 31, 2016 and 2015, respectively. As such, no compensation expense was recognized by our predecessor. In connection with the Corporate Reorganization, the WHR II incentive units were transferred to WildHorse Investment Holdings in exchange for substantially similar incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings granted certain officers and employees awards of incentive units in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The fair value of the incentive units will be remeasured on a quarterly basis until all payments have been made. Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. The payment likelihood related to these incentive units was not deemed probable at December 31, 2017. As such, no compensation expense was recognized by us. Vesting of all incentive units is generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested are forfeited if an employee is no longer employed. All incentive units will be forfeited if a holder resigns whether the incentive units are vested or not. If the payouts have not yet occurred, then all incentive units, whether or not vested, will be forfeited automatically (unless extended).

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 15. Related Party Transactions Corporate Reorganization As described in Note 1, in connection with our initial public offering, we completed certain reorganization transactions pursuant to which we acquired all of the interests in WHR II, Esquisto and Acquisition Co. owned by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively, in exchange for 21,200,084 shares, 38,755,330 shares and 2,563,266 shares, respectively, of our common stock. Board of Directors and Executive Officer Relationships Mr. Grant E. Sims has served as a member of our board of directors since February 2017. Mr. Sims has served as a director and Chief Executive Officer of the general partner of Genesis Energy Partners, L.P. (“Genesis”) since August 2006 and Chairman of the Board of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the fiscal year ended December 31, 2017, we received $2.2 million from Genesis. In addition, Mr. Richard D. Brannon’s son who had been an employee of a CH4 Energy entity (an NGP affiliated company), joined the Company as a non-officer employee in connection with our initial public offering in December 2016. Mr. Brannon’s son received total compensation from us of $0.2 million and less than $0.1 million for the years ended December 31, 2017 and 2016, respectively. Our chief executive officer’s sister-in-law is a non-officer employee of the Company and received total compensation from us of approximately $0.1 million for each of the years ended December 31, 2017, 2016, and 2015, respectively. NGP Affiliated Companies Carlyle Group, L.P. The Carlyle Group, L.P. and certain of its affiliates indirectly own a 55% interest in certain gross revenues of NGP ECM, is a limited partner entitled to 47.5% of the carried interest from NGP XI, and is entitled to 40% of the carried interest from NGP X US Holdings (without, in either case, any rights to vote or dispose of either such fund’s direct or indirect interest in us). NGP ECM manages investment funds, including NGP IX US Holdings, L.P. (“NGP IX US Holdings”), NGP X US Holdings and NGP XI, that collectively directly or indirectly through their equity interests in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings own a majority of our outstanding shares of common stock. As described above, Carlyle purchased 435,000 shares of our Preferred Stock on June 30, 2017. NGP ECM. During the year ended December 31, 2017, we had net disbursements of $0.2 million related to expense reimbursements associated with the corporate reorganization and their services as directors of WRD. CH4 Energy. CH4 Energy entities are NGP affiliated companies and Mr. Brannon, one of our directors, is President of these entities. During the year ended December 31, 2017 we had disbursements of $0.5 million to certain CH4 Energy entities, of which $0.2 million is related to office rental and parking payments and $0.3 million was a reimbursement of landman services and expenses incurred in 2016 that CH4 Energy entities had paid on our behalf. Additionally, the Company acquired incremental leasehold interests from CH4 Energy entities for $0.1 million during the year ended December 31, 2017 in connection with the Corporate Reorganization. Cretic Energy Services, LLC. During the year ended December 31, 2017, 2016 and 2015, we made payments of $0.2 million, $0.4 million and $1.0 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. Garland Exploration, LLC. The Company acquired incremental leasehold interests for $0.1 million during the year ended December 31, 2017 in connection with the Corporate Reorganization. Multi-Shot, LLC. During the year ended December 31, 2015, we made payments of $0.1 million to Multi-Shot, LLC, a NGP affiliated company, for services related to our drilling and completion activities. PennTex Midstream Partners, LP. During the year ended December 31, 2016, we made net payments of $0.2 million to PennTex Midstream Partners, LP (“PennTex”), a NGP affiliated company, for the gathering, processing and transportation of natural gas and NGLs. During the year ended December 31, 2015, we received net payments of $0.1 million. Our related party relationship ceased in the fall of 2016 when a third-party acquired controlling interests in PennTex. Promissory Notes. WHR II issued promissory notes in favor of certain members of WHR II’s management to fund future capital commitments. These promissory notes have been repaid and terminated in 2016. See Note 11 for additional information. WildHorse Resources, LLC. On June 18, 2014, WHR II, through WHRM, began providing accounting and operating transition services to WildHorse Resources, LLC (“WHR”), including administrative and land services, pursuant to the management services agreement. As a result of the management services agreement, WHR II made $57.6 million in net payments to WHR in 2015. On February 25, 2015, the management services agreement was terminated effective March 1, 2015. During the year ended December 31, 2016, we paid net payments of $0.1 million to WHR’s parent company for non-operated working interests in oil and gas properties we operate. WHR ceased being a related party in September 2016 when its parent company was acquired by a third party. NGP X US Holdings LP. Our predecessor paid NGP X US Holdings LP. (“NGP X”) $0.1 million during each year ended December 31, 2016 and 2015 for director fees. In addition, we reimbursed NGP X $0.8 million for certain of our initial public offering related expenses during the year ended December 31, 2016. Previous Owner Related Party Transactions Notes payable to members. During the period from February 17, 2015 to December 31, 2015, Esquisto accrued $3.6 million, as general and administrative expenses payable to its members. Esquisto owed $6.4 million as of December 31, 2015, to its members for general and administrative expenses incurred on its behalf. During the year ended December 31, 2016, Esquisto accrued $4.0 million, as general and administrative expenses payable to its members. These notes were payable to members by December 31, 2022 and bore interest after a year at the Applicable Federal Rate compounded annually paid at maturity. In connection with our initial public offering, the Esquisto notes payable to its members were paid off. Certain CH4 Energy entities received $3.6 million. These CH4 Energy entities are NGP affiliated companies and Mr. Brannon is President of these entities. Garland Exploration, LLC and Crossing Rocks Energy, LLC (“Crossing Rocks”) received $5.5 million and $1.3 million, respectively. These entities are also NGP affiliated companies. Services provided by member. Esquisto paid Calbri Energy, Inc. (“Calbri”), a less than 1% former owner, $0.4 million for the period from February 17, 2015 to December 31, 2015, for completion consulting services. During the year ended December 31, 2016, Esquisto paid Calbri $0.4 million for completion consulting services. Operator. Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $1.3 million during the year ended December 31, 2016 and $0.9 million during the period from February 17, 2015 to December 31, 2015 for overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements and in accordance with an operating agreement between Petromax and Esquisto. Petromax is owned 33.3% by Mike Hoover, the former Chief Operating Officer of Esquisto, who also indirectly owned one of the former members of Esquisto. Related Party Agreements Registration Rights Agreement. We are parties to an amended and restated registration rights agreement with WildHorse Investment Holdings, Esquisto Investment Holdings, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI US Holdings, L.P. (“NGP XI”), Jay Graham and Anthony Bahr (collectively, the “Sponsor Group”), CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), and EIGF Aggregator LLC, TE Admiral A Holding L.P. and Aurora C-1 Holding L.P. (collectively, “KKR”). Pursuant to the amended and restated registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. Demand rights. Subject to the limitations set forth below, at any time after (i) for the Sponsor Group, the 180 day lock-up period, related to our initial public offering, or (ii) for the Carlyle Investor, June 30, 2018, and subject to the limitations set forth below, each member of the Sponsor Group and the Carlyle Investor (or its permitted transferees) have the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a certain number of its shares of our common stock. Generally, we are required to provide notice of the request to certain other holders of our common stock who may, in certain circumstances, participate in the registration. Subject to certain exceptions, we will not be obligated to effect a demand registration within 90 days after the closing of any underwritten offering of shares of our common stock. Further, we are not obligated to effect more than a total of four demand registrations for each of WildHorse Holdings, Esquisto Holdings and WHE Holdings, and more than a total of six demand registrations for the Carlyle Investor. Subject to certain exceptions, we are also not be obligated to effect any demand registration in which the anticipated aggregate offering price for our common stock included in such offering is less than $75 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. We will be required to use reasonable best efforts to maintain the effectiveness of any such registration statement until the earlier of (i) 180 days (or two years in the case of a shelf registration statement) after the effective date thereof or (ii) the date on which all shares covered by such registration statement have been sold (subject to certain extensions). In addition, each member of the Sponsor Group (or its permitted transferees) have the right to require us, subject to certain limitations, to effect a distribution of any or all of its shares of our common stock by means of an underwritten offering. In general, any demand for an underwritten offering (other than the first requested underwritten offering made in respect of a prior demand registration and other than a requested underwritten offering made concurrently with a demand registration) shall constitute a demand request subject to the limitations set forth above. Piggyback Rights. Subject to certain exceptions, if at any time we propose to register an offering of common stock or conduct an underwritten offering, whether or not for our own account, then we must notify each Holder (or its permitted transferees), NGP XI, Mr. Graham, Mr. Bahr, the Carlyle Investor and KKR of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable. KKR was made a Holder under the amended and restated registration rights agreement for purposes of obtaining such piggyback rights. Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective. Stockholders’ Agreement. In connection with our initial public offering, we entered into a stockholders’ agreement with WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings. Among other things, the stockholders’ agreement provides the right to designate nominees to our board of directors as follows: • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own greater than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate up to three nominees to our board of directors; • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 35% of our common stock but less than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate two nominees to our board of directors; • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 15% of our common stock but less than 35% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors and can nominate a third nominee by agreement between them; • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 5% of our common stock but less than 15% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors; and • once WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own less 5% of our common stock, WildHorse Holdings and Esquisto Holdings will not have any board designation rights. Pursuant to the stockholders’ agreement we are required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by WildHorse Holdings and Esquisto Holdings. In addition, the stockholders’ agreement provides that for so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, own at least 15% of the outstanding shares of our common stock, WildHorse Holdings and Esquisto Holdings will have the right to cause any committee of our board of directors to include in its membership at least one director designated by WildHorse Holdings or Esquisto Holdings, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to WildHorse Holdings and Esquisto Holdings to designate directors are additive to and not intended to limit in any way the rights that WildHorse Holdings, Esquisto Holdings, Acquisition Co. or any of their affiliates, including NGP XI, may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the Delaware General Corporation Law. Transition Services Agreement. Upon the closing of our initial public offering, we entered into a transition services agreement with CH4 Energy IV, LLC, PetroMax and Crossing Rocks (collectively, the “Service Providers”), pursuant to which the Service Providers will provide certain engineering, land, operating and financial services to us for six months relating to our Eagle Ford Acreage. In exchange for such services, we agreed to pay a monthly management fee to the Service Providers. NGP and certain former management members of Esquisto own the Service Providers. The transition service agreement was terminated on March 31, 2017 and for the year ended December 31, 2017, we paid the Service Providers $0.1 million.

Segment Disclosures

Segment Disclosures	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Disclosures	Note 16. Segment Disclosures Our chief executive officer has been identified as our chief operating decision maker (“CODM”). We have identified two operating segments – the Eagle Ford and North Louisiana – that have been aggregated into one reportable segment that is engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources in the United States. Our reportable segment includes midstream operations that primarily support the Company’s oil and gas producing activities. There are no differences between reportable segment revenues and consolidated revenues. Furthermore, all of our revenues are from external customers. The Company uses Adjusted EBITDAX as its measure of profit or loss to assess performance and allocate resources. Information regarding assets by reportable segment is not presented because it is not reviewed by the CODM. The following table presents a reconciliation of net income (loss) to Adjusted EBITDAX: For the Year Ended December 31, 2017 2016 2015 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 49,880 $ (47,076 ) $ (33,040 ) Interest expense, net 31,934 7,834 6,943 Income tax (benefit) expense (38,824 ) (5,575 ) 604 Depreciation, depletion and amortization 168,250 81,757 56,244 Exploration expense 36,911 12,026 18,299 Impairment of proved oil and gas properties — — 9,312 (Gain) loss on derivative instruments 55,483 26,771 (13,854 ) Cash settlements received (paid) on derivative instruments 1,517 4,975 11,517 Stock-based compensation 6,644 68 — Acquisition related costs 4,348 553 593 (Gain) loss on sale of properties — 43 — Debt extinguishment costs (11 ) 1,667 — Initial public offering costs 182 1,560 — North Louisiana settlement 7,000 — — Non-cash liability amortization — (286 ) (760 ) Total Adjusted EBITDAX $ 323,314 $ 84,317 $ 55,858 Major Customers The following table sets forth the percentage of our revenues attributed to our customers who have accounted for 10% or more of our revenues during 2017, 2016 or 2015. For the Year Ended December 31, Major Customers 2017 2016 2015 Energy Transfer Equity, L.P. and subsidiaries 56 % 63 % 36 % Royal Dutch Shell plc and subsidiaries 21 % 12 % 20 % Cima Energy LTD n/a 15 % 16 %

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 17. Income Taxes The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2017 2016 2015 Current income taxes: Federal $ (997 ) $ — $ — State (10 ) — — Total income tax benefit (expense) (1,007 ) — — Deferred income taxes: Federal 40,529 5,737 77 State (698 ) (162 ) (681 ) Total deferred income tax benefit (expense) 39,831 5,575 (604 ) Total income tax benefit (expense) $ 38,824 $ 5,575 $ (604 ) The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2017 2016 2015 Expected tax benefit (expense) at federal statutory rate $ (3,870 ) $ 18,428 $ 11,353 State income tax benefit (expense), net of federal benefit (460 ) (105 ) (680 ) Pass-through entities (1) — (12,499 ) (11,315 ) Change in tax rate (2) 43,431 — — Change in prior period estimates (315 ) — — Valuation allowance — (234 ) — Other 38 (15 ) 38 Total income tax benefit (expense) $ 38,824 $ 5,575 $ (604 ) (1) Our predecessor was a pass-through entity for federal income tax purposes. (2) The federal corporate income tax rate was reduced from 35% to 21% as a result of the Tax Cuts and Jobs Act, which was enacted on December 22, 2017. The components of net deferred income tax liabilities are as follows: For the Year Ended December 31, 2017 2016 Deferred income tax assets: Net operating loss carryforwards $ 29,866 $ 2,597 Minimum tax credit carryforward 997 — Asset retirement obligation 3,311 4,083 Derivatives 16,903 8,184 Other 2,153 870 Total deferred income tax assets 53,230 15,734 Valuation allowance — (232 ) Net deferred income tax assets 53,230 15,502 Deferred income tax liabilities: Property, plant and equipment 124,700 127,835 Other — 219 Total deferred income tax liabilities 124,700 128,054 Net deferred income tax liabilities $ 71,470 $ 112,552 Signed into law on December 22, 2017, the Tax Cuts and Jobs Act provides a reduction in the corporate income tax rate from 35% to 21%, effective for tax years beginning after December 31, 2017. The Company recorded a deferred tax benefit of $43.4 million from continuing operations as a result of the re-measurement of its deferred tax assets and liabilities in December 2017, which includes the enactment date. The Company recorded a deferred tax liability of approximately $117.3 million through stockholders’ equity in connection with its initial public offering and the related restructuring transactions in 2016. The tax basis of its assets and liabilities was unchanged as a result of its initial public offering and the related restructuring transactions, which is reported as a transaction among stockholders for financial reporting purposes. Uncertain Income Tax Position. The Company must recognize the tax effects of any uncertain tax positions it may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company had no unrecognized tax benefits as of December 31, 2017 and expects no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2018. Tax Audits and Settlements. Generally, the Company's income tax years 2013 through 2016 remain open and subject to examination by federal and state tax authorities, which include Louisiana and Texas and certain other small state taxing jurisdictions where the Company conducts operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. Tax Attribute Carryforwards and Valuation Allowance. As of December 31, 2017, the Company had federal net operating loss carryforwards of approximately $134.1 million, which would expire in 2036 and 2037. The Company also had state tax carryforwards of approximately $27.0 million, which would expire in 2036 and 2037. In addition, the Company had alternative minimum tax credit carryforwards of approximately $1.0 million, which is not subject to expiration and will be refundable in tax years beginning after 2017 and before 2022. The Company did not record a valuation allowance against its deferred tax assets including tax attributes based upon management’s evaluation that it is more likely than not that the Company will realize its deferred tax assets.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 18. Commitments and Contingencies Litigation & Environmental We are party to various ongoing and threatened legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of December 31, 2017 or 2016. Our estimates are based on information known about the matters and the input of attorneys experienced in contesting, litigating, and settling similar matters. Actual amounts could differ from our estimates and other claims could be asserted. From time to time, we could be liable for environmental claims arising in the ordinary course of business. At December 31, 2017 and 2016, no environmental obligations were recognized. Transportation WHR II was assigned a firm gas transportation service agreement with Regency Intrastate Gas LLC (the “RIGS”) as a result of our property acquisition on August 8, 2013. Under the terms of the agreement, we are obligated to pay total daily transportation fees not to exceed $0.30 per MMBtu per day for quantities of 40,000 MMBtu per day to RIGS until March 5, 2019. This agreement will be assigned to Tanos upon the closing of the NLA Divestiture. Our minimum commitments to RIGS as of December 31, 2017 is as follows (in thousands): 2018 2019 $ 4,380 $ 768 Lease Obligations We currently lease corporate office space through May 31, 2021. Total general and administrative rent expense for the year ended December 31, 2017, 2016 and 2015 was $1.0 million, $0.9 million and $0.8 million, respectively. WHRM entered into the office lease agreement in 2013 that has escalating payments between July 2014 and May 2021. The average annual lease payment is $1.2 million over the life of the lease. We have entered into drilling services agreements with varying terms. We have entered into compressor and equipment rental agreements with various terms. The compressor and equipment rental agreements expire at various times with the latest expiring in March 2017. Most of these agreements contain 30 day termination clauses. Total compressor and equipment rental expense incurred in 2017, 2016 and 2015 was $2.0 million, $0.6 million and $1.0 million, respectively. The table below reflects our minimum commitments as of December 31, 2017: 2018 2019 2020 2021 Office Lease $ 1,259 $ 1,282 $ 1,306 $ 548 Compressor and Equipment 2,263 — — — Total $ 3,522 $ 1,282 $ 1,306 $ 548 Dedicated Fracturing Fleet Services Agreements In 2017, we entered into two dedicated fracturing fleet services agreements to complete wells in a timely manner following conclusion of drilling operations in the Eagle Ford. On March 15, 2017, we entered into a 20-month dedicated fracturing fleet services agreement. The agreement may be extended for an additional twelve months. We have agreed to pay a fixed monthly service fee of $2.7 million that covers equipment and personnel costs. In addition to the fixed monthly service charge, we have agreed to pay a fixed fee for each stage completed in excess of 360 stages per calendar quarter. We have also agreed to pay a pass through fee for the cost of chemicals and fuel plus 10%. We have the right to terminate the contract with appropriate notice; however, an early termination fee of approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on such termination date. On June 1, 2017, we entered into a 23-month dedicated fracturing fleet services agreement, which may be extended for an additional twelve months. We have agreed to pay a fixed monthly service fee of $2.8 million that covers equipment and personnel costs. In addition, we have agreed to pay a fixed fee for each stage completed in excess of 115 stages per month. We have also agreed to pay a pass through fee for the cost of chemicals and fuel plus 10%. We have the right to terminate the contract with appropriate notice; however an early termination fee of $1.4 million times the number of months remaining under the initial term of the contract would be payable on such termination date. Interruptible Water Availability Agreement The Company entered into an interruptible water availability agreement with the Brazos River Authority (“BRA”) that began on February 1, 2017 and ends on December 31, 2021. The agreement provides us with an aggregate of 6,978 acre-feet of water per year from the Brazos River at prices that may be adjusted periodically by BRA. The agreement requires annual payments to be made on or before February 15 of each year during the term of the agreement. We recorded a payment of $0.4 million during the year ended December 31, 2017.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 19. Quarterly Financial Information (Unaudited) The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. First Quarter Second Quarter Third Quarter Fourth Quarter (1) For the Year Ended December 31, 2017 Revenues $ 54,292 $ 70,173 $ 122,486 $ 180,236 Operating income (loss) 6,206 2,078 32,599 $ 64,582 Net income (loss) 20,252 26,366 (10,804 ) $ 14,066 Preferred stock dividends — 73 6,450 6,623 Net income (loss) available to common stockholders 20,252 25,906 (17,254 ) 2,218 Basic earnings per share $ 0.22 $ 0.28 $ (0.17 ) $ 0.06 Diluted earnings per share $ 0.22 $ 0.28 $ (0.17 ) $ 0.06 For the Year Ended December 31, 2016 Revenues $ 25,127 $ 29,715 $ 33,239 $ 39,261 Operating income (loss) (15,005 ) (705 ) 1,458 (1,976 ) Net income (loss) (14,216 ) (18,281 ) 3,057 (17,636 ) Net income (loss) allocated to predecessor (11,699 ) (13,016 ) (2,104 ) (7,179 ) Net income (loss) allocated to previous owner (2,517 ) (5,265 ) 5,161 (60 ) Net income (loss) available to common stockholders n/a n/a n/a (10,397 ) Basic earnings per share n/a n/a n/a $ (0.11 ) Diluted earnings per share n/a n/a n/a $ (0.11 ) (1) Net income for the three months ended December 31, 2017 includes a deferred tax benefit of $43.4 million as a result of the re-measurement of our deferred tax assets and liabilities as a result of the Tax Act.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	Note 20. Supplemental Oil and Gas Information (Unaudited) Oil and Natural Gas Reserves Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our proved reserves are prepared by us and audited by Cawley, our independent reserve engineer. Proved reserves for 2016 were, with respect to WHR II, prepared by WHR II and audited by Cawley. With respect to Esquisto, the proved reserves were prepared by Cawley, its independent reserve engineer, for 2015. Esquisto’s proved reserves for 2016 were internally prepared and audited by Cawley. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. For the Year Ended December 31, 2017 2016 2015 Oil ($/Bbl) West Texas Intermediate (1) $ 51.34 $ 42.75 $ 46.79 NGL ($/Bbl) West Texas Intermediate (1) $ 51.34 $ 42.75 $ 46.79 Natural Gas ($/Mmbtu) Henry Hub (2) $ 2.98 $ 2.48 $ 2.59 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. The following tables set forth estimates of the net reserves as of December 31, 2017, 2016 and 2015, respectively: For the Year Ended December 31, 2017 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 87,447 325,102 10,874 152,505 Extensions, discoveries and additions 93,454 279,368 22,545 162,559 Purchase of minerals in place 59,169 28,106 6,740 70,593 Production (6,606 ) (20,463 ) (1,206 ) (11,222 ) Revision of previous estimates 49,334 71,695 18,597 79,880 End of year 282,798 683,808 57,550 454,315 Proved developed reserves: Beginning of year 19,192 145,880 3,765 47,270 End of year 65,023 221,517 12,553 114,495 Proved undeveloped reserves: Beginning of year 68,255 179,222 7,109 105,235 End of year 217,775 462,291 44,997 339,820 For the Year Ended December 31, 2016 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 36,650 344,959 8,897 103,040 Extensions, discoveries and additions 18,870 32,782 2,606 26,940 Purchase of minerals in place 26,835 13,545 1,823 30,916 Production (1,848 ) (17,820 ) (471 ) (5,289 ) Revision of previous estimates 6,940 (48,364 ) (1,981 ) (3,102 ) End of year 87,447 325,102 10,874 152,505 Proved developed reserves: Beginning of year 7,503 142,990 2,235 33,570 End of year 19,192 145,880 3,765 47,270 Proved undeveloped reserves: Beginning of year 29,147 201,969 6,662 69,470 End of year 68,255 179,222 7,109 105,235 For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 222 249,787 324 42,177 Balance at inception of common control (February 17, 2015) 7,400 6,183 1,637 10,068 Extensions, discoveries and additions 27,598 143,338 5,976 57,464 Purchase of minerals in place 1,972 4,296 710 3,398 Production (968 ) (14,847 ) (351 ) (3,794 ) Revision of previous estimates 426 (43,798 ) 601 (6,273 ) End of year 36,650 344,959 8,897 103,040 Proved developed reserves: Beginning of year 222 122,780 324 21,009 End of year 7,503 142,990 2,235 33,570 Proved undeveloped reserves: Beginning of year — 127,007 — 21,168 End of year 29,147 201,969 6,662 69,470 Noteworthy amounts included in the categories of proved reserve changes in the above tables include: • During 2017, extensions, discoveries and additions increased proved reserves by 20,313 MBoe and 142,246 MBoe related to North Louisiana and Eagle Ford, respectively. • During 2017, purchases of minerals in place of 70,593 MBoe was attributable to the Acquisition. • During 2017, we had upward revisions of 79,880 MBoe, of which 7,461 MBoe related to commodity price changes and 72,419 MBoe was performance related. • During 2016, extensions, discoveries and additions increased proved reserves by 4,131 MBoe and 22,809 MBoe related to drilling in the RCT field in Louisiana and Eagle Ford, respectively. • During 2016, purchase of minerals in place of 30,916 MBoe was primarily attributable to the Burleson North Acquisition. • During 2016, we had downward revisions of proved reserves of 3,102 MBoe, of which 711 MBoe related to commodity price changes and 2,391 MBoe was performance related. • During 2015, extensions, discoveries and additions increased proved reserves by 20,881 MBoe related to drilling in the RCT field in Louisiana by our predecessor. For the period from February 17, 2015 to December 31, 2015, extensions and discoveries increased proved reserves by 36,583 MBoe related to drilling in the Eagle Ford horizons in Burleson County, Texas by the previous owner. • For the period from February 17, 2015 to December 31, 2015, purchase of minerals in place by the previous owner of 3,398 MBoe was primarily attributable to the producing wells acquired from a subsidiary of Comstock Resources, Inc. in July 2015. • During 2015, our predecessor had downward revisions of proved reserves of 7,450 MBoe, of which 3,410 MBoe related to commodity price changes and 4,040 MBoe related to downward revisions resulting from technical changes. For the period from February 17, 2015 to December 31, 2015, revisions of previous estimates attributable to the previous owner were primarily due to operational efficiencies gained through increased experience in the Eagle Ford area (increase of approximately 1,315 MBoe) partially offset by decreased commodity prices which decreased the useful lives of the wells, decreasing ultimate reserves recovered (decrease of approximately 139 MBoe). See Note 3 for additional information on acquisitions and divestitures. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change. The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2017 2016 2015 Future cash inflows $ 16,967,369 $ 4,434,117 $ 2,851,021 Future production costs (3,305,941 ) (1,220,067 ) (866,253 ) Future development costs (4,008,916 ) (1,146,632 ) (741,798 ) Future income tax expense (1,814,510 ) (442,285 ) (216 ) Future net cash flows for estimated timing of cash flows 7,838,002 1,625,133 1,242,754 10% annual discount for estimated timing of cash flows (4,994,097 ) (1,082,092 ) (790,824 ) Standardized measure of discounted future net cash flows $ 2,843,905 $ 543,041 $ 451,930 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2017: For the Year Ended December 31, 2017 2016 2015 Beginning of year $ 543,041 $ 451,930 $ 229,899 Balance at inception of common control (February 17, 2015) — — 215,544 Sale of oil and natural gas produced, net of production costs (351,031 ) (104,596 ) (60,640 ) Purchase of minerals in place 507,095 188,317 69,258 Extensions and discoveries 1,595,385 168,796 261,728 Changes in income taxes, net (488,484 ) (206,817 ) 171 Changes in prices and costs 398,713 (57,034 ) (193,130 ) Previously estimated development costs incurred 49,977 15,067 — Net changes in future development costs (87,375 ) 11,985 1,646 Revisions of previous quantities 653,567 3,943 9,827 Accretion of discount 74,999 103,000 41,859 Change in production rates and other (51,982 ) (31,550 ) (124,232 ) End of year $ 2,843,905 $ 543,041 $ 451,930 Capitalized Costs Relating to Oil and Natural Gas Producing Activities The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. December 31, 2017 2016 2015 Evaluated oil and natural gas properties $ 2,265,525 $ 1,144,857 $ 732,479 Unevaluated oil and natural gas properties 734,203 428,991 251,493 Accumulated depletion, depreciation and amortization (362,406 ) (196,567 ) (117,030 ) Total $ 2,637,322 $ 1,377,281 $ 866,942 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Property acquisition costs, proved $ 269,429 $ 230,910 $ 92,010 Property acquisition costs, unproved 386,515 235,652 176,832 Exploration and extension well costs 16,076 72,875 132,138 Development 795,273 63,006 107,651 Total $ 1,467,293 $ 602,443 $ 508,631

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 21. Subsequent Events Lee County Acquisition On March 1, 2018, we, through our wholly owned subsidiary, WHR EF, closed its acquisition of producing and non-producing properties in Lee County, Texas for approximately $18.6 million from an undisclosed seller. Pending Divestiture of North Louisiana Assets See Note 1—“Organization and Basis of Presentation” for additional information regarding the NLA Divestiture. Sand Mine Acquisition On January 4, 2018, Burleson Sand LLC, a wholly owned subsidiary, acquired surface and sand rights on approximately 727 acres in Burleson County, Texas for approximately $9.0 million to construct and operate an in-field sand mine. Quarterly PIK Dividend See Note 10—“Preferred Stock” for information regarding our quarterly PIK dividend. North Louisiana Settlement On February 1, 2018, we settled a dispute related to a possible area of mutual interest (“AMI”) associated with our North Louisiana assets with a third party. Pursuant to such settlement, the third party agreed to pay the actual net costs attributable to interests in certain leases and/or wells it elected to acquire. We agreed to provide the third party with a $7.0 million credit towards purchasing the interests selected by the third party, which is reflected in the accompanying statements of operations for the year ended December 31, 2017 as “North Louisiana Settlement.” The settlement loss was partially offset by a tax benefit of $1.6 million. A settlement receivable of $5.9 million from the third party was also recognized by us.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Initial Public Offering and Corporate Reorganization	Initial Public Offering and Corporate Reorganization The Company issued and sold to the public in its initial public offering 27,500,000 shares of common stock. The gross proceeds from the sale of the common stock were $412.5 million, net of underwriting discounts of $14.1 million and other offering costs of $5.0 million. The net proceeds from our initial public offering were $393.4 million. Debt issuance costs of $2.9 million related to the establishment of the Company’s revolving credit facility were also incurred in conjunction with our initial public offering. Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation. In May 2017, in connection with the Acquisition (see Note 3), WRD formed WHR Eagle Ford LLC (“WHR EF”) as a wholly owned subsidiary. In November 2017, WRD formed Burleson Sand LLC (“Burleson Sand”) in anticipation of an acquisition of land to develop a sand mine (see Note 21). WHR II has two wholly owned subsidiaries – WildHorse Resources Management Company, LLC (“WHRM”) and Oakfield Energy LLC (“Oakfield”). Esquisto has two wholly owned subsidiaries – Petromax E&P Burleson, LLC, and Burleson Water Resources, LLC (“Burleson Water”). WHRM is the named operator for all oil and natural gas properties owned by us.
Basis of Presentation	Basis of Presentation Our predecessor’s financial statements were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the financial statements included herein (i) (a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (ii) for the period from January 1, 2015 to February 16, 2015. Furthermore, the results of Acquisition Co. are reflected in the financial statements presented herein beginning on December 19, 2016. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Asset retirement obligations were previously separately presented on the consolidated balance sheets and is now being combined with Accrued liabilities on the consolidated balance sheets. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Subsequent Event. On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos Energy Holdings III, LLC (“Tanos”) for the sale of all of our producing and non-producing oil and natural gas properties, including Oakfield, primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”) for a total sales price of approximately $217.0 million (the “NLA Divestiture”), subject to customary purchase price adjustments. The NLA Assets consist of all of our assets in our North Louisiana Acreage. In addition, WRD could receive contingent payments of up to $35.0 million based on the number of wells spud on such properties over the next four years. The effective date of the proposed sale is January 1, 2018, and we expect to close the transaction by the end of March 2018. The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the Purchase and Sale Agreement, Tanos paid WHR II a deposit of $21.7 million at signing, which amount will be applied to the sales price if the transaction closes. The completion of the NLA Divestiture is subject to customary closing conditions. The parties may terminate the Purchase and Sale Agreement by mutual written consent or if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or approximately $43 million, or the transaction has not closed on or before April 30, 2018. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the NLA Assets on the terms or timing described or at all. If the NLA Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our revolving credit facility and for general corporate purposes. Due to asset held-for-sale guidance, we anticipate recording an impairment loss on the NLA Assets during the first quarter of 2018. The net book value of the NLA assets was $415.0 million at December 31, 2017.
Use of Estimates in the Preparation of Financial Statements	Use of Estimates in the Preparation of Financial Statements Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (6) deferred taxes; (7) environmental remediation costs; (8) valuation of derivative instruments; (9) contingent liabilities; and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the Consolidated and Combined Statements of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable.
Restricted Cash	Restricted Cash Restricted cash consists of certificates of deposit in place to collateralize letters of credit. The letters of credit are required as part of normal business operations. The certificates of deposit will be in place for a period greater than 12 months and are considered noncurrent.
Oil and Gas Properties	Oil and Gas Properties We use the successful efforts method of accounting for crude oil and natural gas producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Costs to drill and develop development wells and costs to drill and develop exploratory wells that find proved reserves are also capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed. The following table reflects the net changes in capitalized exploratory well costs for the periods indicated: For Year Ended December 31, 2017 2016 2015 Balance, beginning of period $ 7,064 $ 15,198 $ 11,134 Balance at inception of common control — — 6,385 Additions to capitalized exploratory well costs pending the determination of proved reserves — 60,847 96,726 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (7,064 ) (68,981 ) (93,052 ) Capitalized exploratory well costs charged to expense — — (5,995 ) Balance, end of period $ — $ 7,064 $ 15,198 We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable. We recorded impairment of $20.8 million, $3.1 million and $1.2 million as exploration expense for unproved oil and gas properties for the years ended December 31, 2017, 2016 and 2015, respectively. Our previous owner recorded impairment of $3.3 million as exploration expense for unproved oil and gas properties for the year ended December 31, 2015. Capitalized costs of producing crude oil and natural gas properties and support equipment, net of estimated salvage values, are depleted by field using the units-of-production method. Well and well equipment and tangible property additions are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. We did not record any impairment expense to proved oil and gas properties for the year ended December 31, 2017 and 2016. We recorded impairment expense of $9.3 million to proved oil and gas properties for the year ended December 31, 2015. The impairment resulted from lower projected oil and gas prices and a drop in projected remaining reserves in non-core fields.
Oil and Gas Reserves	Oil and Gas Reserves The estimates of proved crude oil, natural gas, and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Our proved reserves are prepared by us and audited by Cawley, Gillespie & Associates, Inc. (“Cawley”), our independent reserve engineer. Proved reserves for 2016 were, with respect to WHR II, prepared by WHR II and audited by Cawley. With respect to Esquisto, the proved reserves were prepared by Cawley, its independent reserve engineer, for 2015. Esquisto’s proved reserves for 2016 were internally prepared and audited by Cawley. We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 20—“Supplemental Oil and Gas Information (Unaudited)” for further information.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes our natural gas gathering system, Burleson water assets, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized.
Capitalized Interest	Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2017, 2016 and 2015, we recorded $ 3.1 million, $0.1 million and $0.8 million in capitalized interest, respectively.
Properties Acquired in Business Combinations	Properties Acquired in Asset Acquisitions and Business Combinations Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions and Divestitures.”
Asset Retirement Obligations	Asset Retirement Obligations We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production method of the related asset. The accretion expense is included in depreciation, depletion and amortization expense. The fair value of the estimated cost is based on historical experience, managements’ expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated plug and abandonment expense, changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs.
Environmental Costs	Environmental Costs As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Revenue Recognition and Oil and Gas Imbalances	Revenue Recognition and Oil and Gas Imbalances Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. We receive payment approximately one month after delivery for operated crude oil wells, approximately two months after delivery for operated natural gas wells and up to three months after delivery for non-operated wells. Regarding hedge revenue, hedge settlements occur in the same month for natural gas and in the month following for crude oil. Hedge revenue is recorded as a component of “Other income (expense)” on our Statement of Consolidated and Combined Operations. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received.
Incentive Units	Incentive Units For details regarding incentive units issued by our predecessor, please see “Note 14. Incentive Units.”
Accounts Receivable	Accounts Receivable We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of crude oil, natural gas and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties. Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes one month of accrued revenues for operated oil properties, two months of accrued revenues for operated natural gas properties and three months of accrued revenues for non-operated properties net of any collections related to those periods. The accounts receivable balance also includes other miscellaneous balances. Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.1 million at both December 31, 2017 and 2016.
Derivative Instruments	Derivative Instruments We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price commodity swaps, basis swaps, collars and deferred purchased puts. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales. All derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. Changes in fair value are recognized currently in earnings. Realized and unrealized gains and losses from our oil, gas and natural gas liquids derivatives are recorded as a component of “Other income (expense)” on our Statements of Consolidated and Combined Operations. We compute the fair value of the unrealized gains and losses of our derivative instruments using forward prices and dealer quotes provided by a third party. See Note 5—“Risk Management and Derivative and Other Financial Instruments” for additional information regarding our derivative instruments.
Corporate Lease Expenses	Corporate Lease Expenses We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs associated with line-of-credit arrangements, including arrangements with no outstanding borrowings, are classified as an asset, and amortized over the term of the arrangements. Debt issuance costs related to term loans and senior notes are presented as a direct deduction from the carrying amount of the associated debt liability and amortized over the term of the associated debt using the effective yield method.
Fair Value Measurements	Fair Value Measurements Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements of Financial Instruments.”
Income Taxes	Income Taxes We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carry forwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.
Commitments and Contingencies	Commitments and Contingencies Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.
New Accounting Standards	New Accounting Standards Definition of a Business. In January 2017, the FASB issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption was permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption was permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the Leases. In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the required modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standard will extend over future periods. Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step model to analyze contracts to determine when and how revenue is recognized. Central to the five-step model is the concept of control and the timing of the transfer of that control determines the timing of when revenue can be recognized. Control as defined in the standard is the “ability to direct the use of, and obtain substantially all of the remaining benefits from, the asset.” The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 and permits the use of either the full retrospective or cumulative effect transition method. The Company adopted this new standard on January 1, 2018, using the cumulative effect transition method. The cumulative effect transition method requires entities to apply the new standard by recording a cumulative effect adjustment to the opening balance of accumulated earnings based on the impact of applying the standard to contracts that were not completed as of January 1, 2018. The adoption of the new revenue recognition standard does not materially impact the financial position or the results of the operations of the Company; however, two primary differences for our natural gas processing and purchasing contracts are discussed below. Our oil sales contracts are not impacted by the new standard. • First, certain of our contracts require us to make up-front payments to our customers to reimburse them for the cost of installing metering and custody transfer equipment or constructing pipelines from our wells to their facilities. Instead of capitalizing these payments to our Oil and Gas Properties and depleting them, they will be amortized over the period of the benefit and be presented as a reduction to revenue. The difference in accounting will be recognized as an immaterial cumulative effect adjustment to opening accumulated earnings. • Second, the fees we are assessed on certain of our gas processing and purchasing contracts must be reclassified from gathering, processing and transportation expense to revenue. The standard requires these amounts to be a revenue deduction because control of our natural gas under these contracts transfers to our customers prior to the provision of any services by our customers. This difference in presentation of fees will have no impact on our financial position or the results of the operations of the Company. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on our consolidated financial statements and footnote disclosures.
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplement cash flow for the periods presented: For Year Ended December 31, 2017 2016 2015 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 12,246 $ 7,152 $ 7,253 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities 134,589 (4,492 ) 349 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (847 ) (5,175 ) — Due to Hurricane Harvey, the Internal Revenue Service (“IRS”) granted relief to affected taxpayers by allowing taxpayers to defer the deadline for tax return filings and payment of estimated taxes to January 31, 2018. The Company paid $2.3 million related to its 2017 estimated alternative minimum tax to the IRS on January 31, 2018.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Net changes Capitalized Exploratory Costs	The following table reflects the net changes in capitalized exploratory well costs for the periods indicated: For Year Ended December 31, 2017 2016 2015 Balance, beginning of period $ 7,064 $ 15,198 $ 11,134 Balance at inception of common control — — 6,385 Additions to capitalized exploratory well costs pending the determination of proved reserves — 60,847 96,726 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (7,064 ) (68,981 ) (93,052 ) Capitalized exploratory well costs charged to expense — — (5,995 ) Balance, end of period $ — $ 7,064 $ 15,198
Schedule of Supplemental Cash Flow Information	Supplement cash flow for the periods presented: For Year Ended December 31, 2017 2016 2015 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 12,246 $ 7,152 $ 7,253 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities 134,589 (4,492 ) 349 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (847 ) (5,175 ) —

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of Acquisition-Related Costs Included in General and Administrative Expenses	Acquisition-related costs for both related party and third-party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Year Ended December 31, 2017 2016 2015 $ 4,348 $ 553 $ 593
Summary of Fair Value of Assets Acquired and Liabilities Assumed	The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing of the Acquisition (in thousands): Consideration : Cash $ 533,609 Common stock 60,754 Total consideration $ 594,363 Preliminary Purchase Price Allocation: Proved oil and gas properties $ 264,144 Unproved oil and gas properties 333,778 Accounts receivable 967 Asset retirement obligations (2,500 ) Accrued liabilities (2,026 ) Total identifiable net assets $ 594,363 The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands): Purchase Price Oil and gas properties $ 395,591 Other property and equipment 478 Accounts receivable 1,257 Accounts payable (1,816 ) Asset retirement obligations (3,101 ) Accrued liabilities (6,503 ) Total identifiable net assets $ 385,906 The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Comstock Acquisition Oil and gas properties $ 102,628 Other property and equipment 500 Asset retirement obligations (112 ) Total identifiable net assets $ 103,016
Summary of Unaudited Pro Forma Financial Information	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2017 and 2016 as though the Acquisition had been completed on January 1, 2016 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the Acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Year Ended December 31, 2017 2016 Revenues $ 475,396 $ 226,502 Net income (loss) 71,287 (11,290 ) Earnings per share (basic and diluted) $ 0.51 $ (0.10 ) The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 and 2015 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company, the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Year Ended December 31, 2016 2015 Revenues $ 176,082 $ 172,044 Net income (loss) (34,894 ) (83,894 ) Basic and diluted earnings per unit n/a n/a
November Acquisition And Rosewood Acquisition
Summary of Fair Value of Assets Acquired and Liabilities Assumed	The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date for the November Acquisition and Rosewood Acquisition (in thousands): Rosewood Acquisition November Acquisition Oil and gas properties 19,626 29,973

Fair Value Measurements of Fi31

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2017 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 2,422 $ — $ 2,422 Liabilities: Commodity derivatives $ — $ 76,750 $ — $ 76,750 Fair Value Measurements at December 31, 2016 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 7 $ — $ 7 Liabilities: Commodity derivatives $ — $ 22,185 $ — $ 22,185

Risk Management and Derivativ32

Risk Management and Derivative and Other Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts	The following derivative contracts were in place at December 31, 2017: 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 6,834,488 4,537,693 1,101,762 Weighted-average fixed price $ 52.31 $ 52.69 $ 50.19 Collar contracts: Volume (Bbls) 25,096 — — Weighted-average floor price $ 50.00 $ — $ — Weighted-average ceiling price $ 62.10 $ — $ — Put options: Volume (Bbls) 2,666,836 410,525 — Weighted-average floor price $ 51.74 $ 50.00 $ — Weighted-average put premium $ (3.47 ) $ (5.95 ) $ — LLS basis swaps: Volume (Bbls) 3,728,700 — — Spread-WTI $ 3.04 $ — $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 11,825,800 9,877,900 — Weighted-average fixed price $ 3.03 $ 2.81 $ —
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2017 and 2016. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2017 2016 2017 2016 Commodity contracts Short-term derivative instruments $ 2,336 $ 4 $ 58,074 $ 14,091 Netting arrangements Short-term derivative instruments — (4 ) — (4 ) Net recorded fair value $ 2,336 $ — $ 58,074 $ 14,087 Commodity contacts Long-term derivative instruments $ 86 $ 3 $ 18,676 $ 8,094 Netting arrangements Long-term derivative instruments — (3 ) — (3 ) Net recorded fair value $ 86 $ — $ 18,676 $ 8,091
Schedule of Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the years ending December 31, 2017, 2016 and 2015: Statements of For the Year Ended December 31, Operations Location 2017 2016 2015 Commodity derivative contracts Gain (loss) on commodity derivatives $ (55,483 ) $ (26,771 ) $ 13,854

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2017
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following: At December 31, 2017 2016 Oil, gas and NGL sales $ 67,584 $ 13,390 Joint interest billings 9,467 7,898 Severance tax 171 392 North Louisiana Settlement receivable (Note 21) 5,955 — Other current receivables (1) 1,026 4,848 Allowance for doubtful accounts (100 ) (100 ) Total $ 84,103 $ 26,428 (1) At December 31, 2016, primarily relates to a receivable related to our North Burleson Acquisition.
Schedule of Allowance for Doubtful Accounts Activity	The following table presents our allowance for doubtful accounts activity for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Balance at beginning of period $ 100 $ 50 $ — Charged to costs and expenses — 50 50 Balance at end of period $ 100 $ 100 $ 50

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Payables And Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consist of the following: At December 31, 2017 2016 Capital expenditures $ 162,260 $ 17,934 Deferred rent 410 386 Lease operating expense 5,796 2,608 General and administrative 1,642 1,471 Severance and ad valorem taxes 3,463 194 Interest expense 17,177 346 Derivative payable 5,281 428 Income taxes 991 — Other accrued liabilities 2,932 94 Total $ 199,952 $ 23,461

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the year ended December 31, 2017, 2016 and 2015: For the Year Ended December 31, 2017 2016 2015 Asset retirement obligations at beginning of period $ 11,033 $ 7,020 $ 5,935 Balance at inception of common control (February 17, 2015) — — 37 Accretion expense 713 407 354 Liabilities incurred 3,137 3,723 686 Liabilities settled — (5 ) (8 ) Revisions (326 ) (112 ) 16 Asset retirement obligations at end of period 14,557 11,033 7,020 Less: current portion 90 90 90 Asset retirement obligations – long-term $ 14,467 $ 10,943 $ 6,930

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Our debt obligations consisted of the following at the dates indicated: For the Year Ended December 31, Debt Obligation 2017 2016 WRD revolving credit facility $ 286,353 $ 242,750 2025 Senior Notes (as defined below) (1) 500,000 — Unamortized discounts - 2025 Senior Notes (4,914 ) — Unamortized debt issuance costs - 2025 Senior Notes (10,843 ) — Total long-term debt $ 770,596 $ 242,750 (1) The estimated fair value of this fixed-rate debt was $511.3 million at December 31 2017. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
Schedule of Borrowing Base Revolving Credit Facility	The borrowing base for our revolving credit facility was the following at the date indicated (in thousands): December 31, Credit Facility 2017 WRD revolving credit facility $ 875,000
Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: For the Year Ended December 31, Credit Facility 2017 2016 2015 WRD revolving credit facility 3.60 % 3.52 % n/a WHR II revolving credit facility terminated December 2016 n/a 3.03 % 2.60 % Esquisto - revolving credit facility terminated December 2016 n/a 2.84 % 3.13 % Esquisto - revolving credit facility terminated January 2016 n/a 2.97 % 2.97 % Esquisto - Second lien terminated in January 2016 n/a 9.50 % 9.25 %
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated (dollars in thousands): At December 31, 2017 2016 WRD revolving credit facility Current $ 1,203 $ 584 Long-term 3,573 2,320 6.875% senior unsecured notes, due February 2025 10,843 n/a $ 15,619 $ 2,904

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2017
Temporary Equity [Abstract]
Schedule of Preferred Stock	Series A Perpetual Convertible Preferred Stock (in thousands) Balance at December 31, 2016 $ — Issuance of preferred stock in connection with the Acquisition 435,000 Costs incurred related to the issuance of preferred stock (2,663 ) Accrual of preferred stock paid-in-kind dividend 13,146 Balance at December 31, 2017 $ 445,483

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Summary of Changes in Common Shares Issued	The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued since January 1, 2016: Balance, January 1, 2016 (1) — Shares of common stock issued in connection with Corporate Reorganization 62,518,680 Shares of common stock issued in initial public offering 27,500,000 Shares of common stock issued in connection with Rosewood Acquisition 1,308,427 Restricted common shares issued 353,334 Balance, December 31, 2016 91,680,441 Common stock issued 7,815,225 Restricted common shares issued 1,676,284 Restricted common shares forfeited (717 ) Repurchase of vested restricted shares (2) (33,956 ) Balance, December 31, 2017 101,137,277 (1) We were incorporated in August 2016 under the laws of the State of Delaware. (2) Restricted common shares are generally net-settled by 2016 LTIP participants to cover the required withholding tax upon vesting of restricted stock awards. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $0.6 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.
Summary Advances and Payments of Promissory Note Advances	The table below summarizes advances and payments of the promissory note advances for the years ended December 31, 2016 and 2015: Principal Interest Total Balance, December 31, 2014 $ 1,651 $ 39 $ 1,690 Advances 1,096 — 1,096 Payments (380 ) (13 ) (393 ) Accrued Interest — 50 50 Balance, December 31, 2015 2,367 76 2,443 Advances 101 — 101 Payments (20 ) — (20 ) Accrued Interest — 51 51 Dissolution (2,448 ) (127 ) (2,575 ) Balance, December 31, 2016 $ — $ — $ —

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of earnings (loss) per share, or EPS, for the year ended December 31, 2017 and 2016 (in thousands, except per share amounts). In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. For the Year Ended December 31, 2017 2016 Numerator: Net income (loss) available to WRD $ 49,880 $ (10,397 ) Less: Preferred stock dividends 13,146 — Less: Undistributed earnings allocated to participating securities 5,612 — Net income (loss) available to common stockholders $ 31,122 $ (10,397 ) Denominator: Weighted-average common shares outstanding (in thousands) (1) 96,324 91,327 Basic EPS $ 0.32 $ (0.11 ) Diluted EPS (1) $ 0.32 $ (0.11 ) (1) The Company used the two-class method for both basic and diluted EPS. For the twelve months ended December 31, 2017, 628 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the twelve months ended December 31, 2017, 16,008 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

Long Term Incentive Plans (Tabl

Long Term Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Restricted Common Stock Awards Granted Under 2016 LTIP	The following table summarizes information regarding restricted common share awards granted under the 2016 LTIP for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at January 1, 2016 — $ — Granted (2) 353,334 $ 14.50 Restricted common shares outstanding at December 31, 2016 353,334 $ 14.50 Granted (2) 1,676,284 $ 13.88 Forfeited (717 ) $ 13.94 Vested (131,111 ) $ 14.50 Restricted common shares outstanding at December 31, 2017 1,897,790 $ 13.95 (1) Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common share awards granted in 2016 was $5.1 million based on grant date market price of $14.50 per share. The aggregate grant date fair value of restricted common share awards granted in 2017 was $23.3 million based on grant date market price ranging from $10.91 to $14.22 per share.

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Reconciliation of Net Income (Loss) to Adjusted EBITDAX	The following table presents a reconciliation of net income (loss) to Adjusted EBITDAX: For the Year Ended December 31, 2017 2016 2015 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 49,880 $ (47,076 ) $ (33,040 ) Interest expense, net 31,934 7,834 6,943 Income tax (benefit) expense (38,824 ) (5,575 ) 604 Depreciation, depletion and amortization 168,250 81,757 56,244 Exploration expense 36,911 12,026 18,299 Impairment of proved oil and gas properties — — 9,312 (Gain) loss on derivative instruments 55,483 26,771 (13,854 ) Cash settlements received (paid) on derivative instruments 1,517 4,975 11,517 Stock-based compensation 6,644 68 — Acquisition related costs 4,348 553 593 (Gain) loss on sale of properties — 43 — Debt extinguishment costs (11 ) 1,667 — Initial public offering costs 182 1,560 — North Louisiana settlement 7,000 — — Non-cash liability amortization — (286 ) (760 ) Total Adjusted EBITDAX $ 323,314 $ 84,317 $ 55,858
Summary of Major Customers	Major Customers The following table sets forth the percentage of our revenues attributed to our customers who have accounted for 10% or more of our revenues during 2017, 2016 or 2015. For the Year Ended December 31, Major Customers 2017 2016 2015 Energy Transfer Equity, L.P. and subsidiaries 56 % 63 % 36 % Royal Dutch Shell plc and subsidiaries 21 % 12 % 20 % Cima Energy LTD n/a 15 % 16 %

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Components of Income Tax Benefit (Expense)	The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2017 2016 2015 Current income taxes: Federal $ (997 ) $ — $ — State (10 ) — — Total income tax benefit (expense) (1,007 ) — — Deferred income taxes: Federal 40,529 5,737 77 State (698 ) (162 ) (681 ) Total deferred income tax benefit (expense) 39,831 5,575 (604 ) Total income tax benefit (expense) $ 38,824 $ 5,575 $ (604 )
Schedule of Effective Income Tax Rate Reconciliation	The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2017 2016 2015 Expected tax benefit (expense) at federal statutory rate $ (3,870 ) $ 18,428 $ 11,353 State income tax benefit (expense), net of federal benefit (460 ) (105 ) (680 ) Pass-through entities (1) — (12,499 ) (11,315 ) Change in tax rate (2) 43,431 — — Change in prior period estimates (315 ) — — Valuation allowance — (234 ) — Other 38 (15 ) 38 Total income tax benefit (expense) $ 38,824 $ 5,575 $ (604 ) (1) Our predecessor was a pass-through entity for federal income tax purposes. (2) The federal corporate income tax rate was reduced from 35% to 21% as a result of the Tax Cuts and Jobs Act, which was enacted on December 22, 2017.
Components of Net Deferred Income Tax Liabilities	The components of net deferred income tax liabilities are as follows: For the Year Ended December 31, 2017 2016 Deferred income tax assets: Net operating loss carryforwards $ 29,866 $ 2,597 Minimum tax credit carryforward 997 — Asset retirement obligation 3,311 4,083 Derivatives 16,903 8,184 Other 2,153 870 Total deferred income tax assets 53,230 15,734 Valuation allowance — (232 ) Net deferred income tax assets 53,230 15,502 Deferred income tax liabilities: Property, plant and equipment 124,700 127,835 Other — 219 Total deferred income tax liabilities 124,700 128,054 Net deferred income tax liabilities $ 71,470 $ 112,552

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Schedule of Minimum Commitments to RIGS	Our minimum commitments to RIGS as of December 31, 2017 is as follows (in thousands): 2018 2019 $ 4,380 $ 768
Summary of Minimum Commitments of Lease Obligations	The table below reflects our minimum commitments as of December 31, 2017: 2018 2019 2020 2021 Office Lease $ 1,259 $ 1,282 $ 1,306 $ 548 Compressor and Equipment 2,263 — — — Total $ 3,522 $ 1,282 $ 1,306 $ 548

Quarterly Financial Informati44

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. First Quarter Second Quarter Third Quarter Fourth Quarter (1) For the Year Ended December 31, 2017 Revenues $ 54,292 $ 70,173 $ 122,486 $ 180,236 Operating income (loss) 6,206 2,078 32,599 $ 64,582 Net income (loss) 20,252 26,366 (10,804 ) $ 14,066 Preferred stock dividends — 73 6,450 6,623 Net income (loss) available to common stockholders 20,252 25,906 (17,254 ) 2,218 Basic earnings per share $ 0.22 $ 0.28 $ (0.17 ) $ 0.06 Diluted earnings per share $ 0.22 $ 0.28 $ (0.17 ) $ 0.06 For the Year Ended December 31, 2016 Revenues $ 25,127 $ 29,715 $ 33,239 $ 39,261 Operating income (loss) (15,005 ) (705 ) 1,458 (1,976 ) Net income (loss) (14,216 ) (18,281 ) 3,057 (17,636 ) Net income (loss) allocated to predecessor (11,699 ) (13,016 ) (2,104 ) (7,179 ) Net income (loss) allocated to previous owner (2,517 ) (5,265 ) 5,161 (60 ) Net income (loss) available to common stockholders n/a n/a n/a (10,397 ) Basic earnings per share n/a n/a n/a $ (0.11 ) Diluted earnings per share n/a n/a n/a $ (0.11 ) (1) Net income for the three months ended December 31, 2017 includes a deferred tax benefit of $43.4 million as a result of the re-measurement of our deferred tax assets and liabilities as a result of the Tax Act.

Supplemental Oil and Gas Info45

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Weighted Average Benchmark Product Prices	All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. For the Year Ended December 31, 2017 2016 2015 Oil ($/Bbl) West Texas Intermediate (1) $ 51.34 $ 42.75 $ 46.79 NGL ($/Bbl) West Texas Intermediate (1) $ 51.34 $ 42.75 $ 46.79 Natural Gas ($/Mmbtu) Henry Hub (2) $ 2.98 $ 2.48 $ 2.59 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
Summary of changes in quantities of proved oil and natural gas reserves	The following tables set forth estimates of the net reserves as of December 31, 2017, 2016 and 2015, respectively: For the Year Ended December 31, 2017 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 87,447 325,102 10,874 152,505 Extensions, discoveries and additions 93,454 279,368 22,545 162,559 Purchase of minerals in place 59,169 28,106 6,740 70,593 Production (6,606 ) (20,463 ) (1,206 ) (11,222 ) Revision of previous estimates 49,334 71,695 18,597 79,880 End of year 282,798 683,808 57,550 454,315 Proved developed reserves: Beginning of year 19,192 145,880 3,765 47,270 End of year 65,023 221,517 12,553 114,495 Proved undeveloped reserves: Beginning of year 68,255 179,222 7,109 105,235 End of year 217,775 462,291 44,997 339,820 For the Year Ended December 31, 2016 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 36,650 344,959 8,897 103,040 Extensions, discoveries and additions 18,870 32,782 2,606 26,940 Purchase of minerals in place 26,835 13,545 1,823 30,916 Production (1,848 ) (17,820 ) (471 ) (5,289 ) Revision of previous estimates 6,940 (48,364 ) (1,981 ) (3,102 ) End of year 87,447 325,102 10,874 152,505 Proved developed reserves: Beginning of year 7,503 142,990 2,235 33,570 End of year 19,192 145,880 3,765 47,270 Proved undeveloped reserves: Beginning of year 29,147 201,969 6,662 69,470 End of year 68,255 179,222 7,109 105,235 For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 222 249,787 324 42,177 Balance at inception of common control (February 17, 2015) 7,400 6,183 1,637 10,068 Extensions, discoveries and additions 27,598 143,338 5,976 57,464 Purchase of minerals in place 1,972 4,296 710 3,398 Production (968 ) (14,847 ) (351 ) (3,794 ) Revision of previous estimates 426 (43,798 ) 601 (6,273 ) End of year 36,650 344,959 8,897 103,040 Proved developed reserves: Beginning of year 222 122,780 324 21,009 End of year 7,503 142,990 2,235 33,570 Proved undeveloped reserves: Beginning of year — 127,007 — 21,168 End of year 29,147 201,969 6,662 69,470
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2017 2016 2015 Future cash inflows $ 16,967,369 $ 4,434,117 $ 2,851,021 Future production costs (3,305,941 ) (1,220,067 ) (866,253 ) Future development costs (4,008,916 ) (1,146,632 ) (741,798 ) Future income tax expense (1,814,510 ) (442,285 ) (216 ) Future net cash flows for estimated timing of cash flows 7,838,002 1,625,133 1,242,754 10% annual discount for estimated timing of cash flows (4,994,097 ) (1,082,092 ) (790,824 ) Standardized measure of discounted future net cash flows $ 2,843,905 $ 543,041 $ 451,930
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2017: For the Year Ended December 31, 2017 2016 2015 Beginning of year $ 543,041 $ 451,930 $ 229,899 Balance at inception of common control (February 17, 2015) — — 215,544 Sale of oil and natural gas produced, net of production costs (351,031 ) (104,596 ) (60,640 ) Purchase of minerals in place 507,095 188,317 69,258 Extensions and discoveries 1,595,385 168,796 261,728 Changes in income taxes, net (488,484 ) (206,817 ) 171 Changes in prices and costs 398,713 (57,034 ) (193,130 ) Previously estimated development costs incurred 49,977 15,067 — Net changes in future development costs (87,375 ) 11,985 1,646 Revisions of previous quantities 653,567 3,943 9,827 Accretion of discount 74,999 103,000 41,859 Change in production rates and other (51,982 ) (31,550 ) (124,232 ) End of year $ 2,843,905 $ 543,041 $ 451,930
Capitalized Costs Relating to Oil and Natural Gas Producing Activities	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. December 31, 2017 2016 2015 Evaluated oil and natural gas properties $ 2,265,525 $ 1,144,857 $ 732,479 Unevaluated oil and natural gas properties 734,203 428,991 251,493 Accumulated depletion, depreciation and amortization (362,406 ) (196,567 ) (117,030 ) Total $ 2,637,322 $ 1,377,281 $ 866,942
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2017 2016 2015 Property acquisition costs, proved $ 269,429 $ 230,910 $ 92,010 Property acquisition costs, unproved 386,515 235,652 176,832 Exploration and extension well costs 16,076 72,875 132,138 Development 795,273 63,006 107,651 Total $ 1,467,293 $ 602,443 $ 508,631

Organization and Basis of Pre46

Organization and Basis of Presentation - Additional Information (Details) $ in Millions	Feb. 12, 2018USD ($)	Dec. 31, 2016USD ($)shares	Dec. 31, 2017USD ($)Subsidiary
Organization And Basis Of Presentation [Line Items]
Issued and sold of initial public offering | shares		27,500,000
Gross proceeds from the sale of the common stock		$ 412.5
Underwriting Discounts And Commissions		14.1
Other Stock Issuance Costs		5
Net proceeds from initial public offering		393.4
Debt issuance cost		$ 2.9
Net Book Value of North Louisiana Assets, Pending Sale			$ 415
Subsequent Event
Organization And Basis Of Presentation [Line Items]
Total sales price	$ 217
Contingent payments receivable	$ 35
Number of years to receive contingent payments	4 years
Deposits received	$ 21.7
Percentage of adjustments to sales price	20.00%
Adjustments to sales price	$ 43
WHR II
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries | Subsidiary			2
Esquisto
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries | Subsidiary			2

Summary of Significant Accoun47

Summary of Significant Accounting Policies - Schedule of Net changes Capitalized Exploratory Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Balance, beginning of period	$ 7,064	$ 15,198	$ 11,134
Balance at inception of common control	0	0	6,385
Additions to capitalized exploratory well costs pending the determination of proved reserves	0	60,847	96,726
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(7,064)	(68,981)	(93,052)
Capitalized exploratory well costs charged to expense	0	0	(5,995)
Balance, end of period	$ 0	$ 7,064	$ 15,198

Summary of Significant Accoun48

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($)	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policy [Line Items]
Exploration expense		$ 36,911,000	$ 12,026,000	$ 18,299,000
Impairment of proved oil and gas properties		0	0	9,312,000
Capitalized interest		3,100,000	100,000	800,000
Provision for uncollectible accounts		100,000	100,000
Internal Revenue Service (“IRS”) | Subsequent Event
Summary Of Significant Accounting Policy [Line Items]
Estimated minimum tax paid	$ 2,300,000
Unproved Oil And Gas Properties
Summary Of Significant Accounting Policy [Line Items]
Exploration expense		20,800,000	3,100,000	1,200,000
Unproved Oil And Gas Properties | Previous Owner
Summary Of Significant Accounting Policy [Line Items]
Exploration expense				3,300,000
Proved Oil And Gas Properties
Summary Of Significant Accounting Policy [Line Items]
Impairment of proved oil and gas properties		$ 0	$ 0	$ 9,300,000

Summary of Significant Accoun49

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 12,246	$ 7,152	$ 7,253
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities	134,589	(4,492)	349
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions	$ (847)	$ (5,175)	$ 0

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Acquisition-Related Costs Included in General and Administrative Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Combinations [Abstract]
Acquisition-related costs	$ 4,348	$ 553	$ 593

Acquisitions and Divestitures51

Acquisitions and Divestitures - Additional Information (Details) $ in Thousands	Jun. 30, 2017USD ($)shares	Dec. 19, 2016USD ($)ashares	Nov. 08, 2016USD ($)aWell	Jul. 31, 2015USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
APC/KKR Acquisitions
Business Acquisition [Line Items]
Business acquisition, date of acquisition agreement						May 10, 2017
Business acquisition, date of completion						Jun. 30, 2017
Payments to acquire oil and natural gas properties	$ 533,609
Business acquisition, aggregate purchase price, value of shares issued	60,754
Revenues related to properties obtained in the Acquisition						$ 42,600
Income/loss related to properties obtained in the Acquisition						11,100
APC Subs
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties	$ 533,600
KKR
Business Acquisition [Line Items]
Business acquisition, aggregate purchase price, shares issued | shares	5,518,125
Business acquisition, aggregate purchase price, value of shares issued	$ 60,800
Third Parties Acquisition | Burleson County, TX
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties						19,700
Purchase price allocated to unproved oil and natural gas properties						$ 11,600
Burleson North Acquisition
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties		$ 389,800
Revenues related to properties obtained in the Acquisition							$ 2,000
Income/loss related to properties obtained in the Acquisition							$ 400
Purchase price allocated to unproved oil and natural gas properties		$ 162,900
Area of oil and natural gas properties acquired | a		158,000
Business acquisition, post-closing receipt					$ 3,900
Rosewood Acquisition
Business Acquisition [Line Items]
Business acquisition, date of acquisition agreement						Dec. 19, 2016
Business acquisition, aggregate purchase price, shares issued | shares		1,308,427
Purchase price allocated to unproved oil and natural gas properties		$ 18,300
Area of oil and natural gas properties acquired | a		7,500
November Acquisition
Business Acquisition [Line Items]
Business acquisition, date of acquisition agreement						Nov. 8, 2016
Payments to acquire oil and natural gas properties			$ 30,000
Purchase price allocated to unproved oil and natural gas properties			$ 29,400
Area of oil and natural gas properties acquired | a			4,900
Number of oil and Gas producing wells | Well			9
Comstock Acquisition
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties				$ 103,000

Acquisitions and Divestitures52

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 19, 2016	Nov. 08, 2016	Jul. 31, 2015
APC/KKR Acquisitions
Business Acquisition [Line Items]
Cash, Purchase price	$ 533,609
Common stock, Purchase price	60,754
Total consideration, Purchase price	594,363
APC/KKR Acquisitions | Preliminary Purchase Price Allocation
Business Acquisition [Line Items]
Proved oil and gas properties, Purchase price	264,144
Unproved oil and gas properties, Purchase price	333,778
Accounts receivable, Purchase Price	967
Asset retirement obligations, Purchase Price	(2,500)
Accrued liabilities, Purchase Price	(2,026)
Total identifiable net assets, Purchase Price	$ 594,363
Burleson North Acquisition
Business Acquisition [Line Items]
Cash, Purchase price		$ 389,800
Burleson North Acquisition | Final Purchase Price Allocation
Business Acquisition [Line Items]
Oil and gas properties, Purchase Price		395,591
Other property and equipment, Purchase Price		478
Accounts receivable, Purchase Price		1,257
Accounts payable, Purchase Price		(1,816)
Asset retirement obligations, Purchase Price		(3,101)
Accrued liabilities, Purchase Price		(6,503)
Total identifiable net assets, Purchase Price		385,906
Rosewood Acquisition
Business Acquisition [Line Items]
Oil and gas properties, Purchase Price		$ 19,626
November Acquisition
Business Acquisition [Line Items]
Cash, Purchase price			$ 30,000
Oil and gas properties, Purchase Price			$ 29,973
Comstock Acquisition
Business Acquisition [Line Items]
Cash, Purchase price				$ 103,000
Comstock Acquisition | Final Purchase Price Allocation
Business Acquisition [Line Items]
Oil and gas properties, Purchase Price				102,628
Other property and equipment, Purchase Price				500
Asset retirement obligations, Purchase Price				(112)
Total identifiable net assets, Purchase Price				$ 103,016

Acquisitions and Divestitures53

Acquisitions and Divestitures - Summary of Unaudited Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
APC/KKR Acquisitions
Business Acquisition [Line Items]
Revenues	$ 475,396	$ 226,502
Net income (loss)	$ 71,287	$ (11,290)
Earnings per share (basic and diluted)	$ 0.51	$ (0.10)
Burleson North Acquisition
Business Acquisition [Line Items]
Revenues		$ 176,082	$ 172,044
Net income (loss)		$ (34,894)	$ (83,894)
Earnings per share (basic and diluted)		$ 0	$ 0

Fair Value Measurements of Fi54

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value Measurements Recurring - Commodity Derivatives - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets:
Fair value of derivative asset	$ 2,422	$ 7
Liabilities:
Fair value of derivative liability	76,750	22,185
Quoted Prices in Active Market (Level 1)
Assets:
Fair value of derivative asset	0	0
Liabilities:
Fair value of derivative liability	0	0
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	2,422	7
Liabilities:
Fair value of derivative liability	76,750	22,185
Significant Unobservable Inputs (Level 3)
Assets:
Fair value of derivative asset	0	0
Liabilities:
Fair value of derivative liability	$ 0	$ 0

Fair Value Measurements of Fi55

Fair Value Measurements of Financial Instruments - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and gas properties	$ 0	$ 0	$ 9,312,000
Proved Oil And Gas Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and gas properties	$ 0	$ 0	$ 9,300,000

Risk Management and Derivativ56

Risk Management and Derivative and Other Financial Instruments - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017USD ($)
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Deferred premiums	$ 6,300,000
Derivative liabilities	74,300,000
Derivative liability, right to offset amount	0
Cash collateral received or pledged	$ 0

Risk Management and Derivativ57

Risk Management and Derivative and Other Financial Instruments - Schedule of Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2017MMBTU$ / bblbbl
Crude Oil Derivative Contracts Fixed Price Swap 2018
Derivative [Line Items]
Volume (Bbls) | bbl	6,834,488
Weighted-average fixed price	52.31
Crude Oil Derivative Contracts Collar 2018
Derivative [Line Items]
Volume (Bbls) | bbl	25,096
Weighted-average floor price	50
Weighted-average ceiling price	62.10
Crude Oil Derivative Contracts Put Options 2018
Derivative [Line Items]
Volume (Bbls) | bbl	2,666,836
Weighted-average floor price	51.74
Weighted-average put premium	(3.47)
Crude Oil Derivative Contracts LLS Basis Swaps 2018
Derivative [Line Items]
Volume (Bbls) | bbl	3,728,700
Spread-WTI	3.04
Natural Gas Derivative Contracts Fixed Price Swap 2018
Derivative [Line Items]
Weighted-average fixed price	3.03
Volume (MMBtu) | MMBTU	11,825,800
Natural Gas Derivative Contracts Fixed Price Swap 2018
Derivative [Line Items]
Volume (Bbls) | bbl	4,537,693
Weighted-average fixed price	52.69
Crude Oil Derivative Contracts Put Options 2019
Derivative [Line Items]
Volume (Bbls) | bbl	410,525
Weighted-average floor price	50
Weighted-average put premium	(5.95)
Natural Gas Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Weighted-average fixed price	2.81
Volume (MMBtu) | MMBTU	9,877,900
Crude Oil Derivative Contracts Fixed Price Swap 2020
Derivative [Line Items]
Volume (Bbls) | bbl	1,101,762
Weighted-average fixed price	50.19

Risk Management and Derivativ58

Risk Management and Derivative and Other Financial Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Liability Derivatives, Net recorded fair value	$ 74,300
Commodity Derivative Contracts | Short-term Derivative Instruments
Derivative [Line Items]
Asset Derivatives, Gross fair value	2,336	$ 4
Asset Derivatives, Netting arrangements		(4)
Asset Derivatives, Net recorded fair value	2,336
Fair value of derivative liability	58,074	14,091
Liability Derivatives, Netting arrangements		(4)
Liability Derivatives, Net recorded fair value	58,074	14,087
Commodity Derivative Contracts | Long-term Derivative Instruments
Derivative [Line Items]
Asset Derivatives, Gross fair value	86	3
Asset Derivatives, Netting arrangements		(3)
Asset Derivatives, Net recorded fair value	86
Fair value of derivative liability	18,676	8,094
Liability Derivatives, Netting arrangements		(3)
Liability Derivatives, Net recorded fair value	$ 18,676	$ 8,091

Risk Management and Derivativ59

Risk Management and Derivative and Other Financial Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (55,483)	$ (26,771)	$ 13,854
Commodity Derivative Contracts
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (55,483)	$ (26,771)	$ 13,854

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Oil, gas and NGL sales	$ 67,584	$ 13,390
Joint interest billings	9,467	7,898
Severance tax	171	392
North Louisiana Settlement receivable	5,955
Other current receivables	1,026	4,848
Allowance for doubtful accounts	(100)	(100)	$ (50)
Total	$ 84,103	$ 26,428

Accounts Receivable - Schedul61

Accounts Receivable - Schedule of Accounts Notes Loans and Financing Receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounts Notes Loans And Financing Receivable Gross Allowance And Net [Abstract]
Balance at beginning of period	$ 100	$ 50
Charged to costs and expenses	0	50	$ 50
Balance at end of period	$ 100	$ 100	$ 50

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Capital expenditures	$ 162,260	$ 17,934
Deferred rent	410	386
Lease operating expense	5,796	2,608
General and administrative	1,642	1,471
Severance and ad valorem taxes	3,463	194
Interest expense	17,177	346
Derivative payable	5,281	428
Income taxes	991	0
Other accrued liabilities	2,932	94
Total	$ 199,952	$ 23,461

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 11,033	$ 7,020	$ 5,935
Balance at inception of common control (February 17, 2015)	0	0	37
Accretion expense	713	407	354
Liabilities incurred	3,137	3,723	686
Liabilities settled	0	(5)	(8)
Revisions	(326)	(112)	16
Asset retirement obligations at end of period	14,557	11,033	7,020
Less: current portion	90	90	90
Asset retirement obligations – long-term	$ 14,467	$ 10,943	$ 6,930

Long Term Debt - Schedule of De

Long Term Debt - Schedule of Debt Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (15,619)	$ (2,904)
Total long-term debt	770,596	242,750
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Long-term debt, gross	500,000
Unamortized discounts	(4,914)
Unamortized debt issuance costs	(10,843)
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	$ 286,353	$ 242,750

Long Term Debt - Schedule of 65

Long Term Debt - Schedule of Debt Obligations (Parenthetical) (Details) - 6.875% Senior Unsecured Notes, Due February 2025 $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Debt instrument maturity period	Feb. 1, 2025
Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Debt Instrument [Line Items]
Estimated fair value of fixed rate debt	$ 511.3

Long Term Debt - Schedule of Bo

Long Term Debt - Schedule of Borrowing Base Revolving Credit Facility (Details) - USD ($)	Dec. 31, 2017	Oct. 04, 2017	Oct. 03, 2017	Sep. 18, 2017	Jun. 29, 2017	Feb. 01, 2017	Dec. 19, 2016
Line Of Credit Facility [Line Items]
WRD revolving credit facility				$ 650,000,000	$ 450,000,000
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
WRD revolving credit facility	$ 875,000,000	$ 875,000,000	$ 612,500,000			$ 362,500,000	$ 450,000,000

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Details) - USD ($)	Sep. 19, 2017	Feb. 01, 2017	Dec. 19, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 20, 2017	Oct. 04, 2017	Oct. 03, 2017	Sep. 18, 2017	Jun. 29, 2017
Debt Instrument [Line Items]
WRD revolving credit facility										$ 650,000,000	$ 450,000,000
Restricted Payment										$ 75,000,000	$ 50,000,000
Proceeds from senior notes offering				$ 494,744,000	$ 0	$ 0
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Debt instrument interest rate percentage							6.875%
Debt instrument maturity date				Feb. 1, 2025
6.875% Senior Unsecured Notes, Due February 2025 | Private Placement
Debt Instrument [Line Items]
Aggregate principal amount	$ 150,000,000	$ 350,000,000
Debt instrument interest rate percentage		6.875%
Issue price of notes as a percentage of par value	98.26%	99.244%
Proceeds from senior notes offering	$ 144,700,000	$ 338,600,000
Debt instrument maturity date				Feb. 1, 2025
Debt instrument redemption price percentage		106.875%
Debt instrument, redemption description				We may redeem all or any part of the 2025 Senior Notes at a “make-whole” redemption price, plus accrued and unpaid interest, at any time before February 1, 2020. We may also redeem up to 35% of the aggregate principal amount of the 2025 Senior Notes prior to February 1, 2020 in an amount not greater than the net cash proceeds from one or more equity offerings at a redemption price of 106.875% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest.
Maximum | 6.875% Senior Unsecured Notes, Due February 2025 | Private Placement
Debt Instrument [Line Items]
Debt instrument redemption percentage of principal amount		35.00%
Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit expiration period			5 years
Aggregate maximum credit amount			$ 1,000,000,000					$ 2,000,000,000	$ 1,000,000,000
WRD revolving credit facility		$ 362,500,000	$ 450,000,000	$ 875,000,000				$ 875,000,000	$ 612,500,000
Debt issuance date				Dec. 19, 2016
Secured Credit Facility, discount rate			9.00%
Interest description				Borrowings under our revolving credit facility will bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies from 1.25% to 2.25% per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.
Revolving Credit Facility | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Interest rate spread				0.50%
Revolving Credit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Interest rate spread				1.00%
Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Secured Credit Facility lien percentage			85.00%
Commitment fee percentage				0.375%
Ratio of current assets to current liabilities				1
Revolving Credit Facility | Minimum | Adjusted LIBOR
Debt Instrument [Line Items]
Libor Margin				1.00%
Revolving Credit Facility | Minimum | Applicable Market Indexed London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Libor Margin				2.00%
Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Commitment fee percentage				0.50%
Ratio of total debt to EBITDAX				400.00%
Revolving Credit Facility | Maximum | Adjusted LIBOR
Debt Instrument [Line Items]
Libor Margin				2.00%
Revolving Credit Facility | Maximum | Applicable Market Indexed London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Libor Margin				3.00%
Revolving Credit Facility | Certain Properties Prior to February 2, 2017 | Minimum
Debt Instrument [Line Items]
Secured Credit Facility lien percentage			75.00%

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	3.60%	3.52%
WHR II Revolving Credit Facility Terminated December 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.03%	2.60%
Esquisto - Revolving Credit Facility Terminated December 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.84%	3.13%
Esquisto - Revolving Credit Facility Terminated January 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.97%	2.97%
Esquisto - Second Lien Terminated In January 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		9.50%	9.25%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt issuance costs	$ 3,573	$ 2,320
Unamortized deferred financing costs	15,619	2,904
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Unamortized deferred financing costs	10,843
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Current	1,203	584
Debt issuance costs	$ 3,573	$ 2,320

Preferred Stock - Additional In

Preferred Stock - Additional Information (Details) $ / shares in Units, $ in Thousands	Jan. 31, 2018USD ($)$ / shares	Oct. 31, 2017USD ($)	Jul. 31, 2017USD ($)$ / shares	Jun. 30, 2017USD ($)$ / sharesshares	Dec. 31, 2017USD ($)Director$ / sharesshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)
Temporary Equity [Line Items]
Proceeds from the issuance of preferred stock					$ 435,000	$ 0	$ 0
Convertible preferred stock, shares issued | shares					435,000	0
June 30, 2018 Anniversary
Temporary Equity [Line Items]
Conversion of stock, conversion price | $ / shares					$ 13.90
Redeemable Convertible Preferred Stock
Temporary Equity [Line Items]
Quarterly dividend, amount		$ 6,558
Dividend, record date		Oct. 15, 2017
Quarterly dividend, date paid		Oct. 31, 2017
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity [Line Items]
Preferred equity, initial accreted value, per share | $ / shares			$ 1,000
Quarterly dividend announced date			Jul. 31, 2017
Quarterly dividend, amount			$ 2,175
Dividend, record date			Jul. 15, 2017
Redeemable Convertible Preferred Stock | Subsequent Event
Temporary Equity [Line Items]
Quarterly dividend, amount	$ 6,656
Dividend, record date	Jan. 15, 2018
Quarterly dividend, date paid	Jan. 31, 2018
Beneficial conversion feature	$ 1,900
Preferred Stock Purchase Agreement | Carlyle | 10% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Number of directors entitled to be elected upon holding of outstanding common stock | Director					2
Preferred Stock Purchase Agreement | Carlyle | 5% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Number of directors entitled to be elected upon holding of outstanding common stock | Director					1
Preferred Stock Purchase Agreement | Minimum | Carlyle | 10% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Holding percentage of outstanding common stock to elect director					10.00%
Preferred Stock Purchase Agreement | Minimum | Carlyle | 5% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Holding percentage of outstanding common stock to elect director					5.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock
Temporary Equity [Line Items]
Proceeds from the issuance of preferred stock				$ 435,000
Convertible preferred stock, shares issued | shares				435,000
Preferred equity, initial accreted value, per share | $ / shares				$ 1,000
Preferred stock, dividend rate percentage					6.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | December 30, 2019 Anniversary
Temporary Equity [Line Items]
Convertible preferred stock, terms of conversion					The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2021 Anniversary
Temporary Equity [Line Items]
Convertible preferred stock, terms of conversion					the Company may cause the conversion of the Preferred Stock at the Conversion Rate, provided the closing sale price of the common stock equals or exceeds 140% of the Conversion Price for the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert and subject to certain other requirements regarding registration of the shares issuable upon conversion. Notwithstanding the foregoing, the Company shall only be permitted to deliver one conversion notice during any 180-day period and the number of shares of common stock issued upon conversion of the Preferred Stock for which such automatic conversion notice is given shall be limited to 25 times the average daily trading volume of our common stock during the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert.
Number of trading days required for conversion					25 days
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2023 Anniversary
Temporary Equity [Line Items]
Multiple percentage on preferred stock accreted value					112.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2024 Anniversary
Temporary Equity [Line Items]
Multiple percentage on preferred stock accreted value					109.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | After June 30, 2024 Anniversary
Temporary Equity [Line Items]
Multiple percentage on preferred stock accreted value					106.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | Subsequent Event
Temporary Equity [Line Items]
Preferred equity, initial accreted value, per share | $ / shares	$ 1,024
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | Minimum
Temporary Equity [Line Items]
Preferred stock redemption date					Jun. 30, 2022
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | Minimum | December 30, 2019 Anniversary
Temporary Equity [Line Items]
Percentage of preferred stock conversion price					130.00%
Number of trading days required for conversion					25 days
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | Minimum | June 30, 2021 Anniversary
Temporary Equity [Line Items]
Percentage of preferred stock conversion price					140.00%

Preferred Stock - Schedule of P

Preferred Stock - Schedule of Preferred Stock (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Class Of Stock [Line Items]
Balance at December 31, 2016	$ 0
Balance at December 31, 2017	445,483
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock
Class Of Stock [Line Items]
Balance at December 31, 2016	0
Issuance of preferred stock in connection with the Acquisition	435,000
Costs incurred related to the issuance of preferred stock	(2,663)
Accrual of preferred stock paid-in-kind dividend	13,146
Balance at December 31, 2017	$ 445,483

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Jun. 30, 2017	Jan. 17, 2017	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 31, 2015	Feb. 17, 2015
Class Of Stock [Line Items]
Common stock, shares authorized				500,000,000	500,000,000
Common stock, par value				$ 0.01	$ 0.01
Issued and sold of initial public offering					27,500,000
Common stock offering price		$ 15
Proceeds from exercise of over-allotment		$ 32,600
Capital contributions					$ 107,837	$ 334,226
Previous Owner
Class Of Stock [Line Items]
Capital contributions			$ 208,400		97,000
Property contribution			$ 40,100
Excess of investment cost over book value acquired							$ 26,600	$ 16,100
Predecessor
Class Of Stock [Line Items]
Capital contributions					$ 10,837	$ 125,850
Promissory note advances to fund future capital commitments and carried an interest rate					2.50%
KKR
Class Of Stock [Line Items]
Business acquisition, aggregate purchase price, shares issued	5,518,125
Business acquisition, aggregate purchase price, value of shares issued	$ 60,800
Common Stock
Class Of Stock [Line Items]
Issued and sold of initial public offering		2,297,100		7,815,225	27,500,000

Equity - Summary of Changes in

Equity - Summary of Changes in Common Shares Issued (Details) - shares	Jan. 17, 2017	Dec. 19, 2016	Dec. 31, 2017	Dec. 31, 2016
Class Of Stock [Line Items]
Common stock issued				27,500,000
Rosewood Acquisition
Class Of Stock [Line Items]
Shares of common stock issued with corporate reorganization and acquisition		1,308,427
Common Stock
Class Of Stock [Line Items]
Balance, Beginning of Period			91,680,441	0
Common stock issued	2,297,100		7,815,225	27,500,000
Restricted common shares issued			1,676,284	353,334
Balance, End of Period			101,137,277	91,680,441
Restricted common shares forfeited			(717)
Repurchase of vested restricted shares			(33,956)
Common Stock | Corporate Reorganization
Class Of Stock [Line Items]
Shares of common stock issued with corporate reorganization and acquisition				62,518,680
Common Stock | Rosewood Acquisition
Class Of Stock [Line Items]
Shares of common stock issued with corporate reorganization and acquisition				1,308,427

Equity - Summary of Changes i74

Equity - Summary of Changes in Common Shares Issued (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Stockholders Equity Note [Abstract]
Payments for employee withholding taxes	$ 0.6

Equity - Summary of Advances an

Equity - Summary of Advances and Payments of Promissory Note Advances (Details) - Predecessor - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Class Of Stock [Line Items]
Beginning balance	$ 2,443	$ 1,690
Advances	101	1,096
Payments	(20)	(393)
Accrued Interest	51	50
Dissolution	(2,575)
Ending balance	0	2,443
Principal
Class Of Stock [Line Items]
Beginning balance	2,367	1,651
Advances	101	1,096
Payments	(20)	(380)
Accrued Interest	0	0
Dissolution	(2,448)
Ending balance	0	2,367
Interest
Class Of Stock [Line Items]
Beginning balance	76	39
Advances	0	0
Payments	0	(13)
Accrued Interest	51	50
Dissolution	(127)
Ending balance	$ 0	$ 76

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ 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, 2017	Dec. 31, 2016	Dec. 31, 2015
Numerator:
Net income (loss) available to WRD									$ 49,880	$ (10,397)	$ 0
Less: Preferred stock dividends	$ 6,623	$ 6,450	$ 73	$ 0					13,146	0	0
Less: Undistributed earnings allocated to participating securities									5,612	0	0
Net income (loss) available to common stockholders	$ 2,218	$ (17,254)	$ 25,906	$ 20,252	$ (10,397)	$ 0	$ 0	$ 0	$ 31,122	$ (10,397)	$ 0
Denominator:
Weighted-average common shares outstanding									96,324	91,327
Basic	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ (0.11)	$ 0	$ 0	$ 0	$ 0.32	$ (0.11)	$ 0
Diluted	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ (0.11)	$ 0	$ 0	$ 0	$ 0.32	$ (0.11)	$ 0

Earnings Per Share - Schedule77

Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Parenthetical) (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2017shares
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Incremental shares excluded from calculation of diluted EPS	16,008
Restricted Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Incremental shares excluded from calculation of diluted EPS	628

Long Term Incentive Plans - Add

Long Term Incentive Plans - Additional Information (Details) - 2016 Long-Term Incentive Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock authorized for issuance under plan	9,512,500
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized compensation expense	$ 6.6	$ 0.1
Unrecognized compensation cost	$ 21.7
Unrecognized compensation cost, weighted-average period	2 years 4 months 2 days

Long Term Incentive Plans - Sum

Long Term Incentive Plans - Summary of Restricted Common Stock Awards Granted Under 2016 LTIP (Details) - 2016 Long-Term Incentive Plan - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Restricted common shares outstanding, Beginning Balance	353,334	0
Restricted commons shares, Granted	1,676,284	353,334
Restricted commons shares, Forfeited	(717)
Restricted commons shares, Vested	(131,111)
Restricted common shares outstanding, Ending Balance	1,897,790	353,334
Weighted Average Grant Date Fair Value per Share
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Beginning Balance	$ 14.50	$ 0
Restricted common shares, Granted, Weighted-Average Grant Date Fair Value per Share	13.88	14.50
Restricted common shares, Forfeited, Weighted-Average Grant Date Fair Value per Share	13.94
Restricted common shares, Forfeited, Weighted-Average Grant Date Fair Value per Share	14.50
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Ending Balance	$ 13.95	$ 14.50

Long Term Incentive Plans - S80

Long Term Incentive Plans - Summary of Restricted Common Stock Awards Granted Under 2016 LTIP (Parenthetical) (Details) - 2016 Long-Term Incentive Plan - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$ 23.3	$ 5.1
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 13.88	$ 14.50
Restricted Stock | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	10.91
Restricted Stock | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 14.22

Incentive Units - Additional In

Incentive Units - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017USD ($)
WHR II | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive units, maximum range	20.00%
WHR II | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive units, maximum range	40.00%
Incentive Unit Valuation Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized compensation expense	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details)	Jan. 17, 2017shares	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)Directorshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)	Jun. 30, 2017shares
Related Party Transaction [Line Items]
Issued and sold of initial public offering | shares				27,500,000
Preferred stock, shares issued | shares			435,000	0
Initial offering lock-up period			180 days
Anticipated aggregate common stock offering price			$ 75,000,000
Esquisto Notes Payable, Original Maturity Date
Related Party Transaction [Line Items]
Debt instrument maturity date			Dec. 31, 2022
Common Stock
Related Party Transaction [Line Items]
Issued and sold of initial public offering | shares	2,297,100		7,815,225	27,500,000
NGP X US Holdings
Related Party Transaction [Line Items]
Payment made to related party initial public offering expenses				$ 800,000	$ 0
Common stock outstanding shares			15.00%
NGP X US Holdings | Predecessor
Related Party Transaction [Line Items]
Payments made for director fees				100,000	100,000
Stockholders Agreement One | NGP X US Holdings | Maximum
Related Party Transaction [Line Items]
Common stock ownership percentage			50.00%
Stockholders Agreement Two | NGP X US Holdings | Maximum
Related Party Transaction [Line Items]
Common stock ownership percentage			50.00%
Stockholders Agreement Two | NGP X US Holdings | Minimum
Related Party Transaction [Line Items]
Common stock ownership percentage			35.00%
Stockholders Agreement Three | NGP X US Holdings | Maximum
Related Party Transaction [Line Items]
Common stock ownership percentage			35.00%
Stockholders Agreement Three | NGP X US Holdings | Minimum
Related Party Transaction [Line Items]
Common stock ownership percentage			15.00%
Stockholders Agreement Four | NGP X US Holdings | Maximum
Related Party Transaction [Line Items]
Common stock ownership percentage			15.00%
Stockholders Agreement Four | NGP X US Holdings | Minimum
Related Party Transaction [Line Items]
Common stock ownership percentage			5.00%
Esquisto | Drilling and Producing Wells | Maximum
Related Party Transaction [Line Items]
Payments made to related party		$ 900,000		1,300,000
Carlyle Group, L.P.
Related Party Transaction [Line Items]
Preferred stock, shares issued | shares						435,000
Genesis Energy Partners, L.P
Related Party Transaction [Line Items]
Proceeds from sale			$ 2,200,000	0
Non Officer Employees [Member]
Related Party Transaction [Line Items]
Payments made to related party			100,000	100,000	100,000
Cretic Energy Services, LLC | Drilling and Completion Activities
Related Party Transaction [Line Items]
Payments made to related party			200,000	400,000	1,000,000
PennTex Midstream Partners, LP
Related Party Transaction [Line Items]
Proceeds from sale			0	0	100,000
PennTex Midstream Partners, LP | Gathering, Processing and Transportation of Natural Gas and NGLs | Maximum
Related Party Transaction [Line Items]
Net payment made to related party			0	200,000	0
Wild Horse Resources L L C
Related Party Transaction [Line Items]
Payments made to related party					$ 57,600,000
Wild Horse Resources L L C | Transition Service Agreement
Related Party Transaction [Line Items]
Payments made to related party				$ 100,000
Petromax Operating Company, Inc. | Chief Operating Officer of Esquisto
Related Party Transaction [Line Items]
Percentage of ownership				33.30%
Calbri Energy, Inc. | Esquisto | Completion Consulting Services
Related Party Transaction [Line Items]
Payments made to related party		$ 400,000		$ 400,000
Calbri Energy, Inc. | Esquisto | Completion Consulting Services | Maximum
Related Party Transaction [Line Items]
Percentage of ownership		1.00%			1.00%
CH4 Energy
Related Party Transaction [Line Items]
Payments made to related party			500,000
CH4 Energy | Esquisto
Related Party Transaction [Line Items]
Payments made to related party			3,600,000
CH4 Energy | Corporate Reorganization
Related Party Transaction [Line Items]
Leasehold Interests			100,000
CH4 Energy | Office Rental and Parking
Related Party Transaction [Line Items]
Payments made to related party			200,000
CH4 Energy | Landman Services and Expenses
Related Party Transaction [Line Items]
Payments made to related party				300,000
Garland Exploration LLC | Esquisto
Related Party Transaction [Line Items]
Payments made to related party			5,500,000
Garland Exploration LLC | Corporate Reorganization
Related Party Transaction [Line Items]
Leasehold Interests			100,000
Crossing Rocks Energy LLC. | Esquisto
Related Party Transaction [Line Items]
Payments made to related party			1,300,000
Service Providers
Related Party Transaction [Line Items]
Payments made to related party			100,000
NGP ECM
Related Party Transaction [Line Items]
Payments made to related party			$ 200,000
NGP ECM | Maximum
Related Party Transaction [Line Items]
Payments made to related party				$ 100,000
NGP ECM | Carlyle Group, L.P.
Related Party Transaction [Line Items]
Percentage of ownership interest in certain gross revenues			55.00%
NGP ECM | Carlyle Group, L.P. | NGP X US Holdings
Related Party Transaction [Line Items]
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds			40.00%
NGP ECM | Carlyle Group, L.P. | NGP XI
Related Party Transaction [Line Items]
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds			47.50%
WHR II | Corporate Reorganization | Common Stock
Related Party Transaction [Line Items]
Issued and sold of initial public offering | shares				21,200,084
Esquisto | Corporate Reorganization | Common Stock
Related Party Transaction [Line Items]
Issued and sold of initial public offering | shares				38,755,330
Acquisitions [Member] | Corporate Reorganization | Common Stock
Related Party Transaction [Line Items]
Issued and sold of initial public offering | shares				2,563,266
Multi-Shot, LLC | Drilling and Completion Activities
Related Party Transaction [Line Items]
Payments made to related party					$ 100,000
Esquisto
Related Party Transaction [Line Items]
Notes payable to related party, owed		$ 6,400,000			$ 6,400,000
Esquisto | General and Administrative
Related Party Transaction [Line Items]
Payments made for director fees		$ 3,600,000		$ 4,000,000
Wild Horse Holdings And Esquisto Holdings | Director [Member]
Related Party Transaction [Line Items]
Board of Directors nominees | Director			1
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement One | Director [Member]
Related Party Transaction [Line Items]
Board of Directors nominees | Director			3
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Two | Director [Member]
Related Party Transaction [Line Items]
Board of Directors nominees | Director			2
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Three | Director [Member]
Related Party Transaction [Line Items]
Board of Directors nominees | Director			1
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Four | Director [Member]
Related Party Transaction [Line Items]
Board of Directors nominees | Director			1
Wild Horse Holdings And Esquisto Holdings | Esquisto | Stockholders Agreement Five | NGP X US Holdings | Minimum
Related Party Transaction [Line Items]
Common stock ownership percentage			5.00%

Segment Disclosures - Additiona

Segment Disclosures - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017Segment
Segment Reporting [Abstract]
Number of operating segments	2
Number of reportable segments	1

Segment Disclosures - Reconcili

Segment Disclosures - Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Details) - 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, 2017	Dec. 31, 2016	Dec. 31, 2015
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$ 14,066	$ (10,804)	$ 26,366	$ 20,252	$ (17,636)	$ 3,057	$ (18,281)	$ (14,216)	$ 49,880	$ (47,076)	$ (33,040)
Interest expense, net									31,934	7,834	6,943
Income tax (benefit) expense									(38,824)	(5,575)	604
Depreciation, depletion and amortization									168,250	81,757	56,244
Exploration expense									36,911	12,026	18,299
Impairment of proved and unproved oil and gas properties									0	0	9,312
(Gain) loss on derivative instruments									55,483	26,771	(13,854)
Cash settlements received (paid) on derivative instruments									1,517	4,975	11,517
Stock-based compensation									6,644	68	0
Acquisition related costs									4,348	553	593
(Gain) loss on sale of properties									0	43	0
Debt extinguishment costs									(11)	1,667	0
Initial public offering costs									182	1,560	0
North Louisiana settlement									7,000	0	0
Non-cash liability amortization									0	(286)	(760)
Total Adjusted EBITDAX									$ 323,314	$ 84,317	$ 55,858

Segment Disclosures - Major Cus

Segment Disclosures - Major Customers (Details) - Customer Concentration Risk - Sales Revenue, Segment	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Energy Transfer Equity LP. and Subsidiaries.
Concentration risk percentage	56.00%	63.00%	36.00%
Royal Dutch Shell Plc and Subsidiaries.
Concentration risk percentage	21.00%	12.00%	20.00%
Cima Energy Ltd.
Concentration risk percentage	0.00%	15.00%	16.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current income taxes:
Federal	$ (997)	$ 0	$ 0
State	(10)	0	0
Total income tax benefit (expense)	(1,007)	0	0
Deferred income taxes:
Federal	40,529	5,737	77
State	(698)	(162)	(681)
Total deferred income tax benefit (expense)	39,831	5,575	(604)
Total income tax benefit (expense)	$ 38,824	$ 5,575	$ (604)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Effective income tax rate reconciliation, at federal statutory income tax rate, percent			35.00%
Change in tax rate	$ (43,400,000)		$ 43,431,000	$ 0	$ 0
Deferred tax liabilities	124,700,000		124,700,000	128,054,000
Liability for unrecognized tax benefits	0		0
Significant change to unrecognized tax benefits in next twelve months	0		0
Minimum tax credit carryforward	997,000		997,000	0
Valuation allowance	0		0	$ 232,000
Domestic Tax Authority [Member]
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward	134,100,000		$ 134,100,000
Domestic Tax Authority [Member] | Earliest Tax Year
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward expiration year			Dec. 31, 2036
Domestic Tax Authority [Member] | Latest Tax Year
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward expiration year			Dec. 31, 2037
State and Local Jurisdiction [Member]
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward	27,000,000		$ 27,000,000
State and Local Jurisdiction [Member] | Earliest Tax Year
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward expiration year			Dec. 31, 2036
State and Local Jurisdiction [Member] | Latest Tax Year
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward expiration year			Dec. 31, 2037
IPO and Related Restructuring Transactions [Member]
Income Tax Disclosure [Abstract]
Deferred tax liabilities	$ 117,300,000		$ 117,300,000
Scenario, Forecast
Income Tax Disclosure [Abstract]
Effective income tax rate reconciliation, at federal statutory income tax rate, percent		21.00%

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income tax expense benefit continuing operations income tax reconciliation
Expected tax benefit (expense) at federal statutory rate		$ (3,870)	$ 18,428	$ 11,353
State income tax benefit (expense), net of federal benefit		(460)	(105)	(680)
Pass-through entities		0	(12,499)	(11,315)
Change in tax rate (2)	$ (43,400)	43,431	0	0
Change in prior period estimates		(315)	0	0
Valuation allowance		0	(234)	0
Other		38	(15)	38
Total income tax benefit (expense)		$ 38,824	$ 5,575	$ (604)

Income Taxes - Schedule of Ef89

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Contingency [Line Items]
Effective income tax rate reconciliation, at federal statutory income tax rate, percent		35.00%
Scenario, Forecast
Income Tax Contingency [Line Items]
Effective income tax rate reconciliation, at federal statutory income tax rate, percent	21.00%

Income Taxes - Components of Ne

Income Taxes - Components of Net Deferred Income Tax Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred income tax assets:
Net operating loss carryforwards	$ 29,866	$ 2,597
Minimum tax credit carryforward	997	0
Asset retirement obligation	3,311	4,083
Derivatives	16,903	8,184
Other	2,153	870
Total deferred income tax assets	53,230	15,734
Valuation allowance	0	(232)
Net deferred income tax assets	53,230	15,502
Deferred income tax liabilities:
Property, plant and equipment	124,700	127,835
Other	0	219
Total deferred income tax liabilities	124,700	128,054
Net deferred income tax liabilities	$ 71,470	$ 112,552

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	Jun. 01, 2017USD ($)Stage	Mar. 15, 2017USD ($)Stage	Dec. 31, 2017USD ($)MMBTUAgreementacre ft	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Commitments And Contingencies [Line Items]
Accrued liability for existing and potential claims			$ 0	$ 0
Environmental obligations recognized			$ 0	0
Quantities RIGS per day | MMBTU			40,000
Average annual lease payment between July 2014 and May 2021			$ 1,200,000
Compressor and equipment rental agreement latest expiration date			Mar. 31, 2017
Interruptible water availability agreement, start date			Feb. 1, 2017
Interruptible water availability agreement, end date			Dec. 31, 2021
Dedicated Fracturing Fleet Services Agreements
Commitments And Contingencies [Line Items]
Number of agreements entered for completion of wells and drilling operations | Agreement			2
Term of agreement for completion of wells and drilling operations	23 months	20 months
Additional term of agreement for completion of wells and drilling operations	12 months	12 months
Fixed monthly service fee for cost of equipment and personnel	$ 2,800,000	$ 2,700,000
Minimum number of stages to be completed for milestone payments | Stage	115	360
Percentage of amount payable in excess of chemicals and fuel cost	10.00%	10.00%
Early termination fee, description			approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on such termination date.
Early termination fee, approximate multiplier to number of months remaining under initial contract term	$ 1,400,000	$ 1,400,000
Interruptible Water Availability Agreement
Commitments And Contingencies [Line Items]
Aggregate of acre-feet of water per year | acre ft			6,978
Agreement payment			$ 400,000
Compressor and Equipment [Member]
Commitments And Contingencies [Line Items]
Rent Expense			2,000,000	600,000	$ 1,000,000
General and Administrative
Commitments And Contingencies [Line Items]
Rent Expense			1,000,000	$ 900,000	$ 800,000
Maximum
Commitments And Contingencies [Line Items]
Daily transportation fees			$ 0.30

Commitments and Contingencies92

Commitments and Contingencies - Schedule of Future Minimum Commitment (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
Contractual obligation to RIGS, 2018	$ 4,380
Contractual obligation to RIGS, 2019	$ 768

Commitments and Contingencies93

Commitments and Contingencies - Schedule of Future Minimum Lease Obligation (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due 2018	$ 3,522
Operating Leases, Future Minimum Payments, Due 2019	1,282
Operating Leases, Future Minimum Payments, Due 2020	1,306
Operating Leases, Future Minimum Payments, Due 2021	548
Office Lease [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due 2018	1,259
Operating Leases, Future Minimum Payments, Due 2019	1,282
Operating Leases, Future Minimum Payments, Due 2020	1,306
Operating Leases, Future Minimum Payments, Due 2021	548
Compressor and Equipment [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due 2018	2,263
Operating Leases, Future Minimum Payments, Due 2019	0
Operating Leases, Future Minimum Payments, Due 2020	0
Operating Leases, Future Minimum Payments, Due 2021	$ 0

Quarterly Financial accounting

Quarterly Financial accounting (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, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 180,236	$ 122,486	$ 70,173	$ 54,292	$ 39,261	$ 33,239	$ 29,715	$ 25,127	$ 427,187	$ 127,342	$ 86,335
Operating income (loss)	64,582	32,599	2,078	6,206	(1,976)	1,458	(705)	(15,005)	105,465	(16,228)	(39,200)
Net income (loss)	14,066	(10,804)	26,366	20,252	(17,636)	3,057	(18,281)	(14,216)	49,880	(47,076)	(33,040)
Preferred stock dividends	6,623	6,450	73	0					13,146	0	0
Net income (loss) attributable to predecessor					(7,179)	(2,104)	(13,016)	(11,699)	0	(33,998)	(29,955)
Net income (loss) attributable to previous owners					(60)	5,161	(5,265)	(2,517)	0	(2,681)	(3,085)
Net income (loss) available to common stockholders	$ 2,218	$ (17,254)	$ 25,906	$ 20,252	$ (10,397)	$ 0	$ 0	$ 0	$ 31,122	$ (10,397)	$ 0
Basic earnings per share	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ (0.11)	$ 0	$ 0	$ 0	$ 0.32	$ (0.11)	$ 0
Diluted earnings per share	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ (0.11)	$ 0	$ 0	$ 0	$ 0.32	$ (0.11)	$ 0

Quarterly Financial accountin95

Quarterly Financial accounting (Parenthetical) (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Change in tax rate	$ 43,400	$ (43,431)	$ 0	$ 0

Supplemental Oil and Gas Info96

Supplemental Oil and Gas Information - Proved Reserves, Prices (Detail)		12 Months Ended
		Dec. 31, 2017$ / bbl$ / MMBTU	Dec. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2015$ / bbl$ / MMBTU
Oil [Member]
Price of oil and gas	[1]	51.34	42.75	46.79
Natural Gas Liquids [Member]
Price of oil and gas	[1]	51.34	42.75	46.79
Natural Gas [Member]
Price of oil and gas | $ / MMBTU	[2]	2.98	2.48	2.59
[1]	The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.
[2]	The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

Supplemental Oil and Gas Info97

Supplemental Oil and Gas Information - Estimates of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf
Reserve Quantities [Line Items]
Beginning of the year | MBoe	152,505	103,040	42,177
Balance at inception of common control (February 17, 2015) | MBoe			10,068
Extensions, discoveries and additions | MBoe	162,559	26,940	57,464
Purchase of minerals in place | MBoe	70,593	30,916	3,398
Production | MBoe	(11,222)	(5,289)	(3,794)
Revision of previous estimates | MBoe	79,880	(3,102)	(6,273)
End of year | MBoe	454,315	152,505	103,040
Proved developed reserves, Beginning of year | MBoe	47,270	33,570	21,009
Proved developed reserves, End of year | MBoe	114,495	47,270	33,570
Proved undeveloped reserves, Beginning of year | MBoe	105,235	69,470	21,168
Proved undeveloped reserves, End of year | MBoe	339,820	105,235	69,470
Oil [Member]
Reserve Quantities [Line Items]
Beginning of the year	87,447	36,650	222
Balance at inception of common control (February 17, 2015)			7,400
Extensions, discoveries and additions	93,454	18,870	27,598
Purchase of minerals in place	59,169	26,835	1,972
Production	(6,606)	(1,848)	(968)
Revision of previous estimates	49,334	6,940	426
End of year	282,798	87,447	36,650
Proved developed reserves, Beginning of year	19,192	7,503	222
Proved developed reserves, End of year	65,023	19,192	7,503
Proved undeveloped reserves, Beginning of year	68,255	29,147	0
Proved undeveloped reserves, End of year	217,775	68,255	29,147
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of the year | MMcf	325,102	344,959	249,787
Balance at inception of common control (February 17, 2015) | MMcf			6,183
Extensions, discoveries and additions | MMcf	279,368	32,782	143,338
Purchase of minerals in place | MMcf	28,106	13,545	4,296
Production | MMcf	(20,463)	(17,820)	(14,847)
Revision of previous estimates | MMcf	71,695	(48,364)	(43,798)
End of year | MMcf	683,808	325,102	344,959
Proved developed reserves, Beginning of year | MMcf	145,880	142,990	122,780
Proved developed reserves, End of year | MMcf	221,517	145,880	142,990
Proved undeveloped reserves, Beginning of year | MMcf	179,222	201,969	127,007
Proved undeveloped reserves, End of year | MMcf	462,291	179,222	201,969
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning of the year	10,874	8,897	324
Balance at inception of common control (February 17, 2015)			1,637
Extensions, discoveries and additions	22,545	2,606	5,976
Purchase of minerals in place	6,740	1,823	710
Production	(1,206)	(471)	(351)
Revision of previous estimates	18,597	(1,981)	601
End of year	57,550	10,874	8,897
Proved developed reserves, Beginning of year	3,765	2,235	324
Proved developed reserves, End of year	12,553	3,765	2,235
Proved undeveloped reserves, Beginning of year	7,109	6,662	0
Proved undeveloped reserves, End of year	44,997	7,109	6,662

Supplemental Oil and Gas Info98

Supplemental Oil and Gas Information - Estimates of Net Reserves (Parenthetical) (Detail) - MBoe	10 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reserve Quantities [Line Items]
Extensions, discoveries and additions		162,559	26,940	57,464
Purchase of minerals in place		70,593	30,916	3,398
Revision of previous estimates		79,880	(3,102)	(6,273)
Commodity Price Changes [Member]
Reserve Quantities [Line Items]
Revision of previous estimates		7,461	(711)
Performance Related [Member]
Reserve Quantities [Line Items]
Revision of previous estimates		72,419	(2,391)
Commodity Price Change [Member]
Reserve Quantities [Line Items]
Revision of previous estimates	(139)
Eagle Ford [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions	36,583	142,246	22,809
Revision of previous estimates	1,315
RCT field in Louisiana [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions			4,131
North Louisiana [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions		20,313
Predecessor
Reserve Quantities [Line Items]
Revision of previous estimates				(7,450)
Predecessor | Commodity Price Change [Member]
Reserve Quantities [Line Items]
Revision of previous estimates				(3,410)
Predecessor | Technical Changes [Member]
Reserve Quantities [Line Items]
Revision of previous estimates				(4,040)
Predecessor | RCT field in Louisiana [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions				20,881
Previous Owner
Reserve Quantities [Line Items]
Purchase of minerals in place	3,398
Burleson North Acquisition [Member]
Reserve Quantities [Line Items]
Purchase of minerals in place			30,916

Supplemental Oil and Gas Info99

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Additional Information Necessary to Prevent Disclosure of Discounts Future Net Cash Flows from Being Misleading	As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves.

Supplemental Oil and Gas Inf100

Supplemental Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Future cash inflows	$ 16,967,369	$ 4,434,117	$ 2,851,021
Future production costs	(3,305,941)	(1,220,067)	(866,253)
Future development costs	(4,008,916)	(1,146,632)	(741,798)
Future income tax expense	(1,814,510)	(442,285)	(216)
Future net cash flows for estimated timing of cash flows	7,838,002	1,625,133	1,242,754
10% annual discount for estimated timing of cash flows	(4,994,097)	(1,082,092)	(790,824)
Standardized measure of discounted future net cash flows	$ 2,843,905	$ 543,041	$ 451,930	$ 229,899

Supplemental Oil and Gas Inf101

Supplemental Oil and Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Principal Sources Of Change In Standardized Measure Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves [Abstract]
Beginning of year	$ 543,041	$ 451,930	$ 229,899
Balance at inception of common control (February 17, 2015)	0	0	215,544
Sale of oil and natural gas produced, net of production costs	(351,031)	(104,596)	(60,640)
Purchase of minerals in place	507,095	188,317	69,258
Extensions and discoveries	1,595,385	168,796	261,728
Changes in income taxes, net	(488,484)	(206,817)	171
Changes in prices and costs	398,713	(57,034)	(193,130)
Previously estimated development costs incurred	49,977	15,067	0
Net changes in future development costs	(87,375)	11,985	1,646
Revisions of previous quantities	653,567	3,943	9,827
Accretion of discount	74,999	103,000	41,859
Change in production rates and other	(51,982)	(31,550)	(124,232)
End of year	$ 2,843,905	$ 543,041	$ 451,930

Supplemental Oil and Gas Inf102

Supplemental Oil and Gas Information - Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Accumulated depletion, depreciation and amortization	$ (362,406)	$ (196,567)	$ (117,030)
Total	2,637,322	1,377,281	866,942
Evaluated [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated/Unevaluated oil and natural gas properties	2,265,525	1,144,857	732,479
Unevaluated [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated/Unevaluated oil and natural gas properties	$ 734,203	$ 428,991	$ 251,493

Supplemental Oil and Gas Inf103

Supplemental Oil and Gas Information - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Property acquisition costs, proved	$ 269,429	$ 230,910	$ 92,010
Property acquisition costs, unproved	386,515	235,652	176,832
Exploration and extension well costs	16,076	72,875	132,138
Development	795,273	63,006	107,651
Total	$ 1,467,293	$ 602,443	$ 508,631

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) $ in Thousands	Mar. 01, 2018USD ($)	Jan. 04, 2018USD ($)a	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Subsequent Event [Line Items]
North Louisiana settlement			$ 7,000	$ 0	$ 0
Tax benefit used to offset settlement loss with third party			1,600
North Louisiana Settlement receivable			$ 5,955
Subsequent Event | Lee County
Subsequent Event [Line Items]
Payments to acquire oil and natural gas properties	$ 18,600
Subsequent Event | Sand Mine
Subsequent Event [Line Items]
Surface and sand rights acquired | a		727
Payment to acquire surface and sand mineral rights		$ 9,000