Brazos Valley Longhorn, L.L.C. 10-K 4 Mar 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Mar. 04, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Trading Symbol	WRD
Entity Registrant Name	Brazos Valley Longhorn, L.L.C.
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	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Entity Public Float			$ 0

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 14,947	$ 226
Accounts receivable, net	91,558	84,103
Derivative instruments	54,131	2,336
Prepaid expenses and other current assets	7,851	3,290
Total current assets	168,487	89,955
Property and equipment:
Oil and gas properties	3,457,897	2,999,728
Other property and equipment	107,279	53,003
Accumulated depreciation, depletion and amortization	(518,054)	(368,245)
Total property and equipment, net	3,047,122	2,684,486
Other noncurrent assets:
Derivative instruments	18,579	86
Debt issuance costs	3,592	3,573
Other	17,250
Total assets	3,255,030	2,778,100
Current liabilities:
Accounts payable	76,189	53,005
Accrued liabilities	124,633	199,952
Derivative instruments	508	58,074
Total current liabilities	201,330	311,031
Noncurrent liabilities:
Long-term debt	1,191,376	770,596
Asset retirement obligations	8,226	14,467
Deferred tax liabilities	112,731	71,470
Derivative instruments		18,676
Other	2,233	1,085
Total noncurrent liabilities	1,314,566	876,294
Total liabilities	1,515,896	1,187,325
Commitments and contingencies (Note 18)
Stockholders' equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 101,793,855 shares and 101,137,277 shares issued and outstanding at December 31, 2018 and December 31, 2017, respectively	1,018	1,012
Additional paid-in capital	1,153,617	1,118,507
Accumulated earnings	136,773	25,773
Total stockholders' equity	1,291,408	1,145,292
Total liabilities and equity	3,255,030	2,778,100
Preferred Stock
Temporary equity
Preferred stock
Series A Perpetual Convertible Preferred Stock
Temporary equity
Preferred stock	$ 447,726	$ 445,483

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	101,793,855	101,137,277
Common stock, shares outstanding	101,793,855	101,137,277
Preferred Stock
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Series A Perpetual Convertible Preferred Stock
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	500,000	500,000
Preferred stock, shares issued	435,000	435,000
Preferred stock, shares outstanding	435,000	435,000
Preferred stock, involuntary liquidation preference	$ 450,389	$ 448,146

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income:
Other Income	$ 2,052	$ 1,431	$ 2,131
Total operating revenues and other income	947,386	427,187	127,342
Operating expenses:
Lease operating expenses	61,620	39,770	12,320
Gathering, processing and transportation	9,856	11,897	6,581
Taxes other than income tax	52,410	24,158	6,814
Depreciation, depletion and amortization	296,685	168,250	81,757
Impairment of NLA Disposal Group (Note 3)	214,274
Gain on sale of properties	(2,781)		43
General and administrative expenses	65,710	40,663	23,973
Incentive unit compensation expense	13,776
Exploration expense	22,483	36,911	12,026
Other operating expense	1,064	73	99
Total operating expenses	735,097	321,722	143,570
Income (loss) from operations	212,289	105,465	(16,228)
Other income (expense):
Interest expense, net	(60,119)	(31,934)	(7,834)
Gain (loss) on derivative instruments	35,393	(55,483)	(26,771)
North Louisiana settlement (Note 18)		(7,000)
Other income (expense)	(859)	8	(1,818)
Total other expense	(25,585)	(94,409)	(36,423)
Income (loss) before income taxes	186,704	11,056	(52,651)
Income tax benefit (expense)	(40,196)	38,824	5,575
Net income (loss)	146,508	49,880	(47,076)
Net loss attributable to previous owners			(2,681)
Net loss attributable to predecessor			(33,998)
Net income (loss) available to WRD	146,508	49,880	(10,397)
Preferred stock dividends	28,862	13,146
Undistributed earnings allocated to participating securities	30,344	5,612
Net income (loss) available to common stockholders	$ 87,302	$ 31,122	$ (10,397)
Earnings per common share:
Basic	$ 0.88	$ 0.32	$ (0.11)
Diluted	$ 0.88	$ 0.32	$ (0.11)
Weighted-average common shares outstanding:
Basic	99,498	96,324	91,327
Diluted	99,498	96,324	91,327
Oil sales
Revenues and other income:
Revenues	$ 843,244	$ 342,868	$ 75,938
Natural gas sales
Revenues and other income:
Revenues	60,129	59,924	43,487
Natural gas liquid sales
Revenues and other income:
Revenues	$ 41,961	$ 22,964	$ 5,786

STATEMENTS OF CONSOLIDATED AN_2

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 146,508	$ 49,880	$ (47,076)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	296,685	168,250	81,757
Impairments of unproved properties	10,504	20,834	3,051
Impairment of NLA Disposal Group	214,274
Amortization of debt issuance cost	3,098	2,575	479
Accretion of senior note discount	132	342
(Gain) loss on derivative instruments	(35,393)	55,483	26,771
Cash settlements on derivative instruments	(113,637)	1,517	4,975
Deferred income tax expense (benefit)	41,193	(39,831)	(5,575)
Debt extinguishment benefit		(11)	1,667
Amortization of equity awards	19,468	6,644	68
Incentive unit compensation expense	13,776
(Gain) loss on sale of properties	(2,781)		43
Loss on equity investment	676
Consideration paid to customers, net of amortization	(1,817)
Changes in operating assets and liabilities:
Increase in accounts receivable	(8,206)	(56,828)	(16,300)
Increase in prepaid expenses	(576)	(390)	(448)
Increase in inventories	(1,056)	(648)
(Decrease) increase in accounts payable and accrued liabilities	33,678	69,555	(27,150)
Net cash provided by operating activities	616,526	277,372	22,262
Cash flows from investing activities:
Acquisitions of oil and gas properties	(53,814)	(551,242)	(436,072)
Additions to oil and gas properties	(1,051,891)	(700,546)	(125,837)
Additions to and acquisitions of other property and equipment	(83,597)	(15,959)	(5,403)
Contribution to equity method investee	(10,177)
Sales of other property and equipment			102
Proceeds from NLA Divestiture	207,924
Net cash used in investing activities	(991,555)	(1,267,747)	(567,210)
Cash flows from financing activities:
Advances on revolving credit facilities	1,085,000	513,500	383,450
Payments on revolving credit facilities	(867,353)	(469,897)	(378,700)
Debt issuance cost	(4,736)	(15,279)	(3,607)
Termination of second lien			(225)
Proceeds from senior notes offering	204,000	494,744
Proceeds from the issuance of preferred stock		435,000
Proceeds from the issuance of common stock		34,457	412,500
Preferred stock dividends	(20,267)
Previous owner and predecessor contributions			110,280
Repurchase of vested restricted stock	(6,894)	(564)
Net cash provided by financing activities	389,750	986,600	505,272
Net change in cash, cash equivalents and restricted cash	14,721	(3,775)	(39,676)
Cash, cash equivalents and restricted cash, beginning of period	226	4,001	43,677
Cash, cash equivalents and restricted cash, end of period	14,947	226	4,001
Convertible Preferred Stock
Cash flows from financing activities:
Cost incurred in conjunction with the issuance of stock		(2,663)
Common Stock
Cash flows from financing activities:
Cost incurred in conjunction with the issuance of stock	$ 0	$ (2,698)	$ (18,426)

CONSOLIDATED AND COMBINED STATE

CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Thousands	Common Stock	Additional Paid in Capital	Accumulated Earnings (Deficit)	Total
Balance (Predecessor) at Dec. 31, 2015				$ 274,133
Balance (Previous Owner) at Dec. 31, 2015				374,556
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
Net income (loss) | Predecessor				(33,998)
Net income (loss) | Previous Owner				(2,681)
Net income (loss)			$ (10,397)	(47,076)
Proceeds from issuance of common stock	$ 275	$ 412,225		412,500
Costs incurred in connection with issuance of common stock		(19,252)		(19,252)
Notes receivable from members | Predecessor				(132)
Notes receivable from members				(132)
Dissolution of notes receivable from members. | Predecessor				2,575
Dissolution of notes receivable from members.				2,575
Amortization of equity awards	4	64		68
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 shares in connection with acquisition of properties	13	19,613		19,626
Tax related effects in connection with Corporate Reorganization and initial public offering		(117,276)		(117,276)
Balance at Dec. 31, 2016	917	1,017,368	(10,397)	1,007,888
Net income (loss)			49,880	49,880
Proceeds from issuance of common stock	23	34,434		34,457
Costs incurred in connection with issuance of common stock		(1,872)		(1,872)
Amortization of equity awards	17	6,627		6,644
Issuance of shares in connection with acquisition of properties	55	60,699		60,754
Deferred tax adjustment related to initial public offering		1,251		1,251
Preferred stock paid-in-kind dividend			(13,146)	(13,146)
Repurchase of vested restricted common stock			(564)	(564)
Balance at Dec. 31, 2017	1,012	1,118,507	25,773	1,145,292
Net income (loss)			146,508	146,508
Amortization of equity awards	10	19,462		19,472
Preferred stock cash dividend			(20,267)	(20,267)
Preferred stock paid-in-kind dividend			(2,243)	(2,243)
Accrued preferred stock cash dividend			(4,479)	(4,479)
Beneficial conversion feature of preferred stock		1,872		1,872
Amortization of beneficial conversion feature			(1,872)	(1,872)
Repurchase of vested restricted common stock	(4)		(6,890)	(6,894)
Contribution related to incentive unit compensation expense		13,776		13,776
Balance at Dec. 31, 2018	$ 1,018	$ 1,153,617	136,773	1,291,408
Cumulative effect of accounting change (Note 2)			$ 243	$ 243

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation Merger with Chesapeake Energy Corporation In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake. Initial Public Offering and Corporate Reorganization 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, exploration, development and production of oil, natural gas and NGL resources. WHR II, Esquisto II, Acquisition Co., WHR Eagle Ford LLC (“WHR EF”), Burleson Sand LLC (“Burleson Sand”) and WHCC Infrastructure LLC (“WHCC”) are wholly owned subsidiaries of the Company as of December 31, 2018. WildHorse Resources Management Company, LLC (“WHRM”) is a wholly owned subsidiary of WHR II. Esquisto II 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. 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. 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 have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public. 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. Our consolidated and combined financial statements include our accounts and those of our subsidiaries. Restricted cash was previously presented as a component of cash flows from investing activities on the consolidated and combined statements of cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals due to the adoption of a new accounting standard. 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. Investment in Unconsolidated Affiliate WHCC and an undisclosed joint venture partner (“JV Partner”) each made an approximate $10.2 million cash capital contribution for a 50% membership interest in JWH Midstream LLC (“JWH”) during July 2018. JWH used the capital contributions to finance the acquisition of a holding company from a third party that had an existing lease with the Port of Corpus Christi Authority (“Port”) for approximately 55 acres of land on the north side of the Corpus Christi Ship Channel in the Inner Harbor. In December 2018, we accrued an additional $1.9 million capital contribution which was funded in January 2019. A $47.5 million irrevocable standby letter of credit was issued on July 27, 2018 under the Company’s revolving credit facility in favor of the Port to cover future minimum annual wharfage fee payment deficits under the lease. The Port requires that either a guaranty or letter of credit be in place for the first 10 years of the 20-year lease. Until the proposed marine terminal is built and operational, the letter of credit cannot be drawn upon by the Port. We have incurred letter of credit fees of approximately $0.4 million. We determined that JWH is a variable interest entity (“VIE”) due to our disproportionate obligation to absorb losses compared to our voting rights and substantially all of JWH’s current activities involve us. We are exposed to losses above and beyond our 50% membership interest in JWH since we provided the Port with the irrevocable standby letter of credit naming the Port as beneficiary. A reporting entity is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides it with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of the power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances. The Company has determined it is not the primary beneficiary. On the basis of governing provisions set forth in JWH’s limited liability agreement, all decisions regarding activities requires joint or unanimous consent. The power to direct activities that most significantly impact JWH’s economic performance is shared. Our maximum exposure to loss cannot be quantified, but would be limited to our investment and any amounts withdrawn by the Port under the standby letter of credit previously discussed. Our investment in JWH is being accounted as an equity method investee. Investments in a limited liability company that maintains a specific ownership account for each investor should generally be accounted for under the equity method of accounting unless the investment is so minor that the member may have virtually no influence over the company’s operating and financial policies. In practice, investments of more than 3 to 5 percent are viewed as more than minor. Our $11.5 million investment in JWH is reflected on our balance sheet under other noncurrent assets as a component of the “Other” financial statement line item. Equity losses of $0.7 million for the year ended December 31, 2018 is reflected on our income statement under other income (expense) as a component of the “Other income (expense)” financial statement line item.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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, natural gas and NGL 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 income 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 Historically, restricted cash consisted of certificates of deposit in place to collateralize letters of credit. The letters of credit were required as part of normal business operations. The certificates of deposit were in place for a period greater than 12 months and were considered noncurrent. We had no restricted cash at December 31, 2018 and 2017. 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. Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed. We have excluded capitalized costs of $98.1 million at December 31, 2018. 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 (in thousands): For Year Ended December 31, 2018 2017 2016 Balance, beginning of period $ — $ 7,064 $ 15,198 Additions to capitalized exploratory well costs pending the determination of proved reserves — — 60,847 Reclassifications to wells, facilities and equipment based on the determination of proved reserves — (7,064) (68,981) Capitalized exploratory well costs charged to expense — — — Balance, end of period $ — $ — $ 7,064 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 $10.5 million, $20.8 million and $3.1 million as exploration expense for unproved oil and gas properties for the years ended December 31, 2018, 2017 and 2016, respectively. 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 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 Cawley, Gillespie & Associates, Inc. ("CG&A"), a third-party independent reserve engineer. 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 sand mine, saltwater disposal wells, 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, 2018, 2017 and 2016, we recorded $5.9 million, $3.1 million and $0.1 million in capitalized interest, respectively. Properties Acquired in Asset Acquisitions and Business Combinations For asset acquisitions, the purchase price recorded at cost and is allocated to identifiable assets on a relative fair value basis. Therefore, we would need to determine the fair value of the assets at acquisition. 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 from Contracts with Customers Our revenues are derived through the sale of our hydrocarbon production, specifically the sale of crude oil, natural gas and NGLs. On January 1, 2018 the Company adopted ASC 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) to all contracts that were not completed as of January 1, 2018 using the cumulative effect transition method. The cumulative effect of adopting the standard was recognized through an adjustment to opening accumulated earnings. The new revenue 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.” We review our contracts through the five-step model at inception, and as any new contracts are executed or existing contracts are modified, to determine when to recognize revenue. We expect the overall impact to net income to be immaterial on an ongoing basis. Previous periods have not been revised or adjusted and reflect the revenue standard in effect for those periods. Under the previous revenue recognition standard, revenues were recognized when the product was delivered at a fixed and determinable price, title transferred and collectability was reasonably assured and evidenced by a contract. Crude oil sales contracts We have performance obligations under our crude oil sales contracts to deliver barrels of oil, where each barrel of oil is considered to be its own performance obligation under the new revenue standard. Volumes are generally not predetermined and pricing for the crude oil is index-based, adjusted for location and other economic factors. We recognize revenue from the sale of our crude oil at a point in time, when we transfer control of the crude oil to our purchaser, which occurs when the oil passes through our facilities (typically a tank battery or our third-party contracted trucks) into our purchaser’s receiving equipment (typically a truck or their pipeline). Once the crude oil has been delivered, we have fulfilled our obligation and we no longer have the ability to direct the use of, or obtain any of the remaining benefits from that crude oil. Sales of crude oil are presented on the “Oil sales” line item of our statement of operations. The adoption of the new revenue standard did not result in any material changes to the accounting or presentation of oil sales. Natural gas sales contracts Our natural gas contracts stipulate that we deliver unprocessed natural gas to a contractually specified delivery point. Once the natural gas enters our customer’s facilities, it may be compressed, dehydrated, treated, separated into residue gas (predominately methane) and NGLs, or otherwise processed. For a majority of our natural gas sales contracts, the Company transfers control of the natural gas (which could include both residue gas and NGLs) to our customer upon delivery into their facilities and we recognize revenue at that point in time. Our performance obligation within these contracts is to deliver unprocessed natural gas. Once delivered, we have fulfilled our obligation and our customers have full control over the use, sale or disposition of the gas. Any charges assessed to us by our customer, including but not limited to gathering, processing, compression, treating and dehydration are considered to be a reduction to the transaction price because we did not receive a distinct good or service from the customer. Services are not deemed to be provided to us because the related activities occur after we transfer control of the gas to our customer. Prior to the adoption of the new revenue standard, these charges were reported within “Gathering, processing and transportation” expense in our statement of operations, while these costs are now being netted against revenues. For the other portion of our natural gas sales contracts, our contracts are structured such that both the customer and the Company have shared contractual control over the natural gas. Contractual terms dictate that payment to us is based on actual extracted volumes of NGLs/residue gas. Further, the contracts stipulate that a portion of that processed gas is retained by our customer as compensation for their services, thereby incentivizing the customer to process our gas and operate their facilities efficiently in our best interest. Under these contracts, the value associated with the volumes our customer retains and any charges assessed by our customer are recognized on our “Gathering, processing and transportation” expense line item. This is because the gas is contractually controlled jointly by both us and our customer until our performance obligation is fulfilled at the tailgate of our customer’s plant (once processing has been completed). Our performance obligation under these contracts is to sell the extracted NGLs and residue gas. We recognize revenue at a point in time (at the plant tailgate) when we have fulfilled our performance obligation. Prior to the adoption of the new revenue standard, we did not recognize the volumes retained by our customer as an expense and we reported revenues net of the volumes they retained. Residue gas contracts In certain of the natural gas sales contracts discussed above, the residue gas separated during plant processing is not sold to the processor but is instead redelivered back to us at the tailgate of the plant. We directly market these volumes to third parties using index-based natural gas prices and utilize our pipeline capacity (under our transportation agreements) to deliver these volumes from the plant tailgate to market. Our performance obligation in our residue gas contracts is the delivery of residue gas. Control over residue gas transfers upon delivery, at which point we have fulfilled our performance obligation and can recognize revenue. Performance obligations fulfilled in a prior period We record revenue in the month oil or natural gas volumes are delivered to the customer, based on estimated production, prices and revenue deductions. Any variances between our estimates and the actual amounts received are generally recorded one month after delivery for operated oil sales, two months after delivery for operated natural gas and NGL sales and three months after delivery for non-operated oil, natural gas and NGL sales. Disaggregation of revenue The new revenue standard requires that we disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Our statement of operations disaggregates revenue to reflect pricing realities present in our contracts with our customers. The terms of our natural gas sales contracts stipulate that the pricing we receive for our unprocessed natural gas will be based on the volumes of lower value natural gas and higher value NGLs present in the unprocessed natural gas we deliver. Fees assessed by our customers (that reduce revenue) are allocated between gas and NGLs on a volumetric basis or based upon the nature of the fee. Contributions in aid of construction 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. These long-term assets are amortized over the period of the benefit and are presented as a reduction to natural gas and NGL revenue or as a gathering, processing and transportation expense. Prior to the adoption of the new revenue standard, these assets were recorded to our “Oil and gas properties” line item on the balance sheet and depleted using the units of production method. As depicted below, we adjusted the balance sheet and accumulated earnings for the cumulative effect of this accounting change. The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of the new revenue standard is as follows (in thousands): At December 31, Adjustments for At January 1, 2017 ASC 606 2018 Assets: Oil and gas properties $ 2,999,728 $ (4,041) $ 2,995,687 Accumulated depreciation, depletion and amortization (368,245) 371 (367,874) Other non-current assets — 3,978 3,978 Liabilities: Deferred tax liabilities $ 71,470 $ 67 $ 71,537 Stockholders’ Equity: Accumulated earnings (deficit) $ 25,773 $ 243 $ 26,016 Other topics Production Imbalances - 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. Contract assets - The new revenue standard requires certain disclosure around contract assets. Contract assets are rights to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditional on something other than the passage of time. We have an unconditional right to payment upon completion of our performance obligations and have therefore recorded no contract assets as of December 31, 2018. Unsatisfied performance obligations - We have no unsatisfied performance obligations under our contracts. The majority of our contracts do not have stated volumes and we consider our performance obligations to be satisfied upon transfer of control of the commodity. In our remaining contracts where we are obligated to deliver a stated volume, all volumes are delivered in the period and we do not have any unsatisfied performance obligations under those contracts at the end of a period. Other Income - During the period, we owned the Oakfield gathering system, substantial fresh water supply and storage, a saltwater disposal well and several compressors. Though the Oakfield gathering system, saltwater disposal well and compressors were sold to Tanos Energy Holdings III, LLC (“Tanos”) as part of the NLA Divestiture (see Note 3 - "Acquisitions and Divestitures"), these assets were used during the period in the operations of our wells. Non-operators who own a portion of our wells are billed for the use of these assets, utilizing rates based on industry-accepted joint interest accounting rules and market conditions. We report income from this source as “Other income” on our statement of operations in accordance with accounting guidance on collaborative arrangements. Operating expenses related to these activities are recorded to the “Other operating (income) expense” line item on the statement of operations. Prior to the adoption of the new revenue standard, income net of expenses from saltwater disposal wells and compressors were recorded within lease operating expense and income net of expenses for the Burleson water supply and storage assets were recorded within other income. In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement, balance sheet and statement of cash flows was as follows (in thousands): For the Year Ended December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Revenues: Oil sales $ 843,244 $ 843,329 $ (85) Natural gas sales 60,129 64,896 (4,767) NGL sales 41,961 51,052 (9,091) Other Income 2,052 1,861 191 Operating expenses: Lease operating expenses 61,620 63,043 (1,423) Gathering, processing and transportation 9,856 22,703 (12,847) Depreciation, depletion and amortization 296,685 297,295 (610) Other operating expense 1,064 459 605 Income before income taxes 186,704 186,180 524 Income tax expense (40,196) (40,083) (113) Net income 146,508 146,097 411 At December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,457,897 $ 3,463,857 $ (5,960) Accumulated depreciation, depletion and amortization (518,054) (519,035) 981 Other non-current assets 17,250 11,439 5,811 Liabilities: Deferred tax liabilities 112,731 112,551 180 Stockholders' Equity Accumulated earnings 136,773 137,785 (1,012) For the Year Ended December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ 146,508 $ 146,097 $ 411 Depreciation, depletion and amortization 296,685 297,295 (610) Deferred income tax expense 41,193 41,080 113 Consideration paid to customers, net of amortization (1,817) — (1,817) Cash flows from investing activities: Additions to oil and gas properties (1,051,891) (1,053,811) 1,920 Incentive Units For details regarding incentive units, 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 $0.2 million and $0.1 million at December 31, 2018 and 2017, respectively. 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. For our forward commodity contracts that meet the definition of a derivative, we have elected the normal purchases and normal sales scope exclusion, because we believe it is probable that physical delivery of the product will occur under the contract and we do not intend on net settling the contract. Therefore, all activity under these contracts was recorded as revenue in our consolidated financial statements. 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 or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in Other income (expense) in our Consolidated and Combined Statement of Operations. 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 Supplemental cash flow for the periods presented (in thousands): For Year Ended December 31, 2018 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 48,717 $ 12,246 $ 7,152 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (82,358) 134,589 (4,492) (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (1,247) (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 Financial Accounting Standards Board (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. The Company adopted this guidance on January 1, 2018 on a prospective basis 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

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2018
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 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, 2018 2017 2016 $ 1,117 $ 4,348 $ 553 2018 Acquisitions Eagle Ford Shale Acquisitions. During the year ended December 31, 2018, we closed on multiple transactions to acquire certain acreage and associated production from third parties for approximately $53.8 million. These transactions were accounted for as asset acquisitions since substantially all the fair value was concentrated in a group of similar assets. As such, an additional $1.5 million of acquisition costs were capitalized as part of these acquisitions. We assigned $48.0 million to unproved oil and natural gas properties. Sand Mine Acquisition. On January 4, 2018, Burleson Sand 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. Our capitalized sand assets were $66.1 million at December 31, 2018. 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 $ 533,002 Common stock 60,754 Total consideration $ 593,756 Final Purchase Price Allocation Proved oil and gas properties $ 264,467 Unproved oil and gas properties 333,778 Accounts receivable 60 Asset retirement obligations (2,500) Accrued liabilities (2,049) Total identifiable net assets $ 593,756 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 the 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 November 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 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 Revenues $ 176,082 Net loss $ (34,894) Basic and diluted earnings per unit n/a 2018 Divestiture On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with 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”). On March 29, 2018, we completed the sale of the NLA Assets for a total net sales price of approximately $206.4 million, including final purchase price adjustments of $4.8 million, the final sales price of $211.2 million has been fully collected at December 31, 2018. The Company has paid $3.8 million in expenses related to the divestiture and has received $0.4 million in contingent payments from Tanos. In addition, the Company could receive contingent payments of up to $35.0 million, based on the number of wells spud on such properties over the next three years. Our contingent consideration arrangement is not recognized as a derivative under the guidance and, accordingly, we have made an accounting policy election to record the contingent consideration when it is deemed to be realizable. We received $0.4 million in contingent payments from Tanos. Our NLA Assets were deemed to meet held-for-sale accounting criteria as of February 12, 2018, at which point we ceased recording depletion and depreciation. Based on the Company’s sale proceeds after customary preliminary purchase price adjustments, we recorded an impairment charge of $214.3 million during the first quarter of 2018 to adjust the carrying amount of the disposal group (“NLA Disposal Group”) to its estimated fair value less costs to sell. The impairment is reflected on our Unaudited Statements of Condensed Consolidated Operations as “Impairment of NLA Disposal Group.” For the years ended December 31, 2018 and 2017, the NLA Disposal Group had pre-tax losses of $202.7 million and $5.9 million, respectively. During the year ended December 31, 2018, we recognized a gain of $2.8 million. We received a $4.8 million final settlement payment from Tanos in October 2018. We provided Tanos with transitional accounting and land services during the three months ended June 30, 2018 and recognized $0.9 million of fees as a reduction to our general and administrative expenses.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017, 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, 2018 and December 31, 2017. 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, 2018 and December 31, 2017 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, 2018 and 2017 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2018 Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 72,710 $ — $ 72,710 Liabilities: Commodity derivatives $ — $ 508 $ — $ 508 Fair Value Measurements at December 31, 2017 Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 2,422 $ — $ 2,422 Liabilities: Commodity derivatives $ — $ 76,750 $ — $ 76,750 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 initial 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. The initial fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See “Note 8—Asset Retirement Obligations” 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. We did not record impairments on proved properties for the year ended December 31, 2018, 2017 and 2016. · Unproved oil and natural gas properties and other assets are reviewed for impairment based on passage of time or geologic factors. Information such as remaining lease terms, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved properties are deemed to be impaired, the expense is recorded as a component of exploration expenses. For the years ended December 31, 2018, 2017 and 2016, we recorded $10.5 million, $20.8 million and $3.1 million of impairments of unproved properties, respectively. · We recorded an impairment associated with the NLA Assets during the first quarter of 2018. See Note 3—“Acquisitions and Divestitures” for additional information.

Risk Management and Derivative

Risk Management and Derivative and Other Financial Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure
Risk Management and Derivative 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, historically, used 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 years ended December 31, 2018 and 2017 is net of deferred premiums of $9.3 million and $6.3 million, respectively. 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, 2018 we had net derivative assets of $72.2 million. Had certain counterparties failed completely to perform according to the terms of existing contracts, we would have the right to offset $72.2 million against amounts outstanding under our revolving credit facility, thereby eliminating any credit exposure. The following derivative contracts were in place at December 31, 2018: 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 6,652,369 4,511,681 Weighted-average fixed price $ 54.45 $ 53.49 Put options: Volume (Bbls) 1,749,757 — Weighted-average floor price $ 53.83 $ — Weighted-average put premium $ (5.43) $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 6,425,146 4,846,020 Weighted-average fixed price $ 2.79 $ 2.76 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, 2018 and 2017. 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 (in thousands) (in thousands) Type Balance Sheet Location 2018 2017 2018 2017 Commodity contracts Short-term derivative instruments $ 54,131 $ 2,336 $ 508 $ 58,074 Netting arrangements Short-term derivative instruments — — — — Net recorded fair value $ 54,131 $ 2,336 $ 508 $ 58,074 Commodity contacts Long-term derivative instruments $ 18,579 $ 86 $ — $ 18,676 Netting arrangements Long-term derivative instruments — — — — Net recorded fair value $ 18,579 $ 86 $ — $ 18,676 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, 2018, 2017 and 2016 (in thousands): Statements of For the Year Ended December 31, Operations Location 2018 2017 2016 Commodity derivative contracts Gain (loss) on derivative instruments $ 35,393 $ (55,483) $ (26,771)

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2018
Receivables [Abstract]
Accounts Receivable	Note 6. Accounts Receivable Accounts receivable consist of the following (in thousands): At December 31, 2018 2017 Oil, gas and NGL sales $ 70,900 $ 67,584 Joint interest billings 17,491 9,467 Severance tax 1,352 171 Derivative receivable 308 — North Louisiana Settlement receivable — 5,955 Environmental remediation 1,511 — Other current receivables 196 1,026 Allowance for doubtful accounts (200) (100) Total $ 91,558 $ 84,103 The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): 2018 2017 2016 Balance at beginning of period $ 100 $ 100 $ 50 Charged to costs and expenses 100 — 50 Balance at end of period $ 200 $ 100 $ 100

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2018
Payables And Accruals [Abstract]
Accrued Liabilities	Note 7. Accrued Liabilities Accrued liabilities consist of the following (in thousands): At December 31, 2018 2017 Capital expenditures $ 80,897 $ 162,260 Preferred stock cash dividends 4,479 — Deferred rent — 410 Lease operating expense 6,604 5,796 General and administrative 4,335 1,642 Severance and ad valorem taxes 5,283 3,463 Interest expense 20,122 17,177 Derivative payable 1,746 5,281 Income taxes — 991 Other accrued liabilities 1,167 2,932 Total $ 124,633 $ 199,952

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 (in thousands): For the Year Ended December 31, 2018 2017 Asset retirement obligations at beginning of period $ 14,557 $ 11,033 Accretion expense 573 713 Liabilities incurred 743 3,137 Liabilities settled — — Revisions 70 (326) Disposition of wells and gathering system (7,627) — Asset retirement obligations at end of period 8,316 14,557 Less: current portion 90 90 Asset retirement obligations – long-term $ 8,226 $ 14,467

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long Term Debt	= 90% 250.0 bps 150.0 bps 50.0 bps >= 75%; < 90% 225.0 bps 125.0 bps 50.0 bps >=50%; < 75% 200.0 bps 100.0 bps 50.0 bps >= 25%; < 50% 175.0 bps 75.0 bps 37.5 bps < 25% 150.0 bps 50.0 bps 37.5 bps 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 may also automatically decrease upon the issuance of certain debt, including senior 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 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 per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies 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. 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. On September 19, 2017, we completed a 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. Additionally, on April 20, 2018, we completed a private placement of $200.0 million aggregate principal amount of our 2025 Senior Notes (the “April Notes”) issued at 102.00% of par, which resulted in net proceeds of approximately $201.0 million. The notes issued in September 2017 and April 2018 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 February 2017, September 2017 and April 2018 offerings of the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes. The indenture governing the 2025 Senior Notes (the "2025 Indenture") contains customary reporting covenants (including furnishing quarterly and annual reports to the holders of the 2025 Senior Notes) and restrictive covenants that, among other things, restrict the ability of the Company and its subsidiaries to: (i) pay dividends on, purchase or redeem the Company's equity interests or purchase or redeem subordinated debt; (ii) make certain investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create or incur certain secured debt; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company's assets; (vii) enter into agreements that restrict distributions or other payments from the Company's restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated before the 2025 Senior Notes mature if at any time no default or event of default exists under the 2025 Indenture and the 2025 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The 2025 Indenture also contains customary events of default. Pursuant to the registration rights agreements entered into in connection with the 2017 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 then-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. Pursuant to a registration rights agreement entered into in connection with the issuance of the April Notes, we agreed to file a registration statement with the SEC so that holders of the April Notes could exchange the unregistered April Notes for registered notes that have substantially identical terms. In addition, we agreed to exchange the unregistered guarantees related to the April Notes for registered guarantees having substantially identical terms. On September 24, 2018, all of the then-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: At December 31, Credit Facility 2018 2017 2016 WRD revolving credit facility 4.06 % 3.60 % 3.52 % WHR II revolving credit facility terminated December 2016 n/a n/a 3.03 % Esquisto - revolving credit facility terminated December 2016 n/a n/a 2.84 % Esquisto - revolving credit facility terminated January 2016 n/a n/a 2.97 % Esquisto - Second lien terminated in January 2016 n/a n/a 9.50 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated (in thousands): At December 31, 2018 2017 WRD revolving credit facility Current $ 1,823 $ 1,203 Long-term 3,592 3,573 6.875% senior unsecured notes, due February 2025 11,842 10,843 Total $ 17,257 $ 15,619" id="sjs-B4">Note 9. Long Term Debt Our debt obligations consisted of the following (in thousands): At December 31, Debt Obligation 2018 2017 WRD revolving credit facility $ 504,000 $ 286,353 2025 Senior Notes (as defined below) (1) 700,000 500,000 Unamortized net discounts - 2025 Senior Notes (782) (4,914) Unamortized debt issuance costs - 2025 Senior Notes (11,842) (10,843) Total long-term debt $ 1,191,376 $ 770,596 (1) The estimated fair value of this fixed-rate debt was $661.5 million and $511.3 million at December 31, 2018 and 2017, respectively. The estimated fair values are 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 2018 WRD revolving credit facility $ 1,300,000 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- "Preferred Stock"), (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. On March 23, 2018, 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 Fourth Amendment to the Credit Agreement (the “Fourth Amendment”). The Fourth Amendment, among other things, modified the Credit Agreement to increase the borrowing base from $875.0 million to $1.05 billion. On October 15, 2018, 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 Fifth Amendment to the Credit Agreement (the “Fifth Amendment”). The Fifth Amendment, among other things, (i) modified the Credit Agreement to increase the borrowing base from $1.05 billion to $1.30 billion and (ii) decreased the pricing grid by 25 basis points across the grid as seen in the following table: Borrowing Base Utilization LIBOR Margin Base Rate Margin Commitment Fee >= 90% 250.0 bps 150.0 bps 50.0 bps >= 75%; < 90% 225.0 bps 125.0 bps 50.0 bps >=50%; < 75% 200.0 bps 100.0 bps 50.0 bps >= 25%; < 50% 175.0 bps 75.0 bps 37.5 bps < 25% 150.0 bps 50.0 bps 37.5 bps 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 may also automatically decrease upon the issuance of certain debt, including senior 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 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 per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies 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. 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. On September 19, 2017, we completed a 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. Additionally, on April 20, 2018, we completed a private placement of $200.0 million aggregate principal amount of our 2025 Senior Notes (the “April Notes”) issued at 102.00% of par, which resulted in net proceeds of approximately $201.0 million. The notes issued in September 2017 and April 2018 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 February 2017, September 2017 and April 2018 offerings of the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes. The indenture governing the 2025 Senior Notes (the "2025 Indenture") contains customary reporting covenants (including furnishing quarterly and annual reports to the holders of the 2025 Senior Notes) and restrictive covenants that, among other things, restrict the ability of the Company and its subsidiaries to: (i) pay dividends on, purchase or redeem the Company's equity interests or purchase or redeem subordinated debt; (ii) make certain investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create or incur certain secured debt; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company's assets; (vii) enter into agreements that restrict distributions or other payments from the Company's restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated before the 2025 Senior Notes mature if at any time no default or event of default exists under the 2025 Indenture and the 2025 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The 2025 Indenture also contains customary events of default. Pursuant to the registration rights agreements entered into in connection with the 2017 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 then-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. Pursuant to a registration rights agreement entered into in connection with the issuance of the April Notes, we agreed to file a registration statement with the SEC so that holders of the April Notes could exchange the unregistered April Notes for registered notes that have substantially identical terms. In addition, we agreed to exchange the unregistered guarantees related to the April Notes for registered guarantees having substantially identical terms. On September 24, 2018, all of the then-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: At December 31, Credit Facility 2018 2017 2016 WRD revolving credit facility 4.06 % 3.60 % 3.52 % WHR II revolving credit facility terminated December 2016 n/a n/a 3.03 % Esquisto - revolving credit facility terminated December 2016 n/a n/a 2.84 % Esquisto - revolving credit facility terminated January 2016 n/a n/a 2.97 % Esquisto - Second lien terminated in January 2016 n/a n/a 9.50 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated (in thousands): At December 31, 2018 2017 WRD revolving credit facility Current $ 1,823 $ 1,203 Long-term 3,592 3,573 6.875% senior unsecured notes, due February 2025 11,842 10,843 Total $ 17,257 $ 15,619

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2018
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 $ — Issue 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 Paid-in-kind dividend 2,243 Beneficial conversion feature ("BCF") (1,872) Amortization of BCF 1,872 Balance at December 31, 2018 $ 447,726 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 from issuance until January 31, 2018, our board of directors 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 The terms of our outstanding preferred stock require us to pay a quarterly dividend. Because we are legally obligated to pay cumulative dividends, whether or not declared, we accrue the dividends as earned. The declaration of a dividend after the balance sheet date, but before the financial statements are issued is considered to be a recognizable subsequent event that provides additional evidence about conditions that existed at the date of the balance sheet. A recognized subsequent event is to be recognized in the financial statements as if they occurred before the balance sheet date. Declaration of paid-in-kind dividends subsequent to the balance sheet date are recorded as an increase to the carrying amount of the preferred stock. Declaration of a cash dividends subsequent to the balance sheet date are recorded as an accrued liability. 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 was for the period beginning on August 1, 2017 to October 31, 2017 and was paid to holders of record on October 15, 2017. 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 was 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 was amortized over the earliest Preferred Stock conversion period as additional dividends. The table below summarizes the quarterly cash dividends paid to holders of record at the dates indicated of our preferred stock: Period Covered Date of Record From To Cash Dividends Paid Payment Date (in millions) April 15, 2018 February 1, 2018 April 30, 2018 $ April 30, 2018 July 15, 2018 May 1, 2018 July 31, 2018 $ July 31, 2018 October 15, 2018 August 1, 2018 October 31, 2018 $ October 31, 2018 Subsequent Event. On January 31, 2019, an aggregate quarterly cash dividend of $6.831 million was paid to holders of record as of January 15, 2019 for the period from November 1, 2018 to February 1, 2019. In connection with the Merger and in accordance with the voting agreement with Carlyle, all the Company's preferred stock was converted into the Company's common stock prior to the effective time of the Merger.

Equity

Equity	12 Months Ended
	Dec. 31, 2018
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 December 31, 2016: 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 Restricted common shares issued 1,076,165 Restricted common shares forfeited (63,768) Repurchase of vested restricted shares (2) (355,819) Balance, December 31, 2018 101,793,855 (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 $6.9 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. 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- "Acquisitions and Divestitures" 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 years ended December 31, 2018 and 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 from its members during the year ended December 31, 2016, 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 year ended December 31, 2016 (in thousands): Principal Interest Total 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 from its members during the year ended December 31, 2016. As a result of the Corporate Reorganization (as discussed in Note 1) and common control accounting, Esquisto's net assets were recorded at NGP's historical cost basis.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2018
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 years ended December 31, 2018, 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, 2018 (1) 2017 (2) 2016 (3) Numerator: Net income (loss) available to WRD $ 146,508 $ 49,880 $ (10,397) Less: Preferred stock dividends 28,862 13,146 — Less: Undistributed earnings allocated to participating securities 30,344 5,612 — Net income (loss) available to common stockholders $ 87,302 $ 31,122 $ (10,397) Denominator: Weighted-average common shares outstanding (in thousands) 99,498 96,324 91,327 Basic EPS $ 0.88 $ 0.32 $ (0.11) Diluted EPS $ 0.88 $ 0.32 $ (0.11) (1) The Company used the two-class method for both basic and diluted EPS. For the year ended December 31, 2018, 775 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the for the year ended December 31, 2018, 32,363 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method. (2) The Company used the two-class method for both basic and diluted EPS. For the year 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 year 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. (3) The Company used the two-class method for both basic and diluted EPS. For the year ended December 31, 2016, restricted shares were excluded from the calculation of diluted EPS due to their antidilutive effect as we were in a loss position for the period.

Long Term Incentive Plans

Long Term Incentive Plans	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
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: Weighted-Average Number of Grant Date Fair Shares Value per Share (1) Restricted common shares outstanding at January 1, 2016 — $ — Granted (2) 353,334 $ 14.50 Restricted common stock 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 stock outstanding at December 31, 2017 1,897,790 $ 13.95 Granted (2) 1,076,165 $ 25.57 Forfeited (63,768) $ 16.45 Vested (1,069,933) $ 15.66 Restricted common stock outstanding at December 31, 2018 1,840,254 $ 19.66 (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 2017 was $23.3 million based on grant date market price ranging from $10.91 to $14.22 per share. The aggregate grant date fair value of restricted common share awards granted in 2018 was $27.5 million based on grant date market price ranging from $18.14 to $27.07 per share. Our awards have contractual vesting periods between one and three years. For the year ended December 31, 2018, 2017 and 2016, we recorded $19.5 million, $6.6 million and less than $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 $28.7 million at December 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years. We elect to account for forfeitures on share-based payments by recognizing forfeitures of awards as they occur. Subsequent event. In January 2019, all outstanding shares granted under the 2016 LTIP were supervested. On February 1, 2019, the shares were converted to common shares of Chesapeake using the conversion method elected by the shareholder as outlined in the merger agreement.

Incentive Units

Incentive Units	12 Months Ended
	Dec. 31, 2018
Compensation Related Costs [Abstract]
Incentive Units	Note 14. Incentive Units Prior to December 31, 2018, c ertain officers and employees were granted awards of incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (the “LLCs”). Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date or as a result of an actual distribution. Compensation cost related to an actual distribution by Esquisto Holdings to incentive unitholders of 500,932 shares of our common stock on May 14, 2018 resulted in non-cash compensation expense of $13.8 million offset by a deemed capital contribution. Compensation costs associated with satisfying the remaining performance conditions were not deemed probable at December 31 , 2018. All incentive units not vested are forfeited upon a termination of employment. 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). Subsequent event. In connection with the Merger, all unvested incentive units became fully vested in accordance with their terms and will remain outstanding following the effective time of the merger. See “Note 1—Organization and Basis of Presentation” for information regarding our merger with Chesapeake.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
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 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 directors of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. We received $1.2 million and $2.2 million for the years ended December 31, 2018 and 2017, respectively, from Genesis. Ms. Stephanie Hildebrandt has served as a member of our board of directors since December 2017. Ms. Hildebrandt has served as Senior Vice President, General Counsel, and Secretary of Archrock Inc., (“Archrock”) since August 2017. Archrock is a provider of compression services. During the year ended December 31, 2018, we had disbursements of $0.1 million to Archrock. 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, which 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 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. An affiliate of the Carlyle Group, L.P. purchased 435,000 shares of our preferred stock on June 30, 2017. NGP ECM. During the year ended December 31, 2017, we had disbursements of $0.2 million related to director and advisory fees and reimbursement of initial public offering costs. We did not have any related party payments or receipts for the year ended December 31, 2018. CH4 Energy. CH4 Energy entities are NGP affiliated companies and Mr. Brannon, a former member of our board of directors, is President of these entities. During the year ended December 31, 2018 we had disbursements of $0.2 million to certain CH4 Energy entities for office rental and parking payments. During the year ended December 31, 2017 we had disbursements of $0.5 million to certain CH4 Energy entities, of which $0.3 million was a reimbursement of landman services and expenses incurred in 2016 that CH4 Energy entities had paid on our behalf and $0.2 million was related to office rental and parking payments. 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, we had disbursements of $0.2 million to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities. We did not have any related party payments for the year ended December 31, 2018. 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. We have in effect a registration on Form S‑3, therefore, any such demand registration would 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; however, as of December 31, 2018, they no longer own any of our common stock. 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.

Segment Disclosures

Segment Disclosures	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Disclosures	Note 16. Segment Disclosures Our chief executive officer has been identified as our chief operating decision maker (“CODM”). As of December 31, 2018, we identified one operating segment and one reportable segment—the Eagle Ford—that is engaged in the acquisition, exploration, development and production of oil, natural gas and NGL resources in the United States. Historically, we had two operating segments – the Eagle Ford and North Louisiana – that were aggregated into one reportable segment. On March 29, 2018 we closed the NLA Divestiture, which involved substantially all of the assets previously included in our North Louisiana operating segment. See Note 3- "Acquisitions and Divestitures" for additional information related to the NLA Divestiture. Our reportable segment includes midstream operations that primarily support the Company’s oil and natural gas producing activities. There are no differences between reportable segment revenues and consolidated revenues. Furthermore, all of our revenues are from external 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 2018, 2017 or 2016. For the Year Ended December 31, Major Customers 2018 2017 2016 Energy Transfer Equity, L.P. and subsidiaries 49 % 56 % 63 % Koch Industries, Inc. 19 % 4 % n/a Royal Dutch Shell plc and subsidiaries 18 % 21 % 12 % Cima Energy LTD n/a n/a 15 %

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 17. Income Taxes The components of income tax expense (benefit) are as follows (in thousands): For the Year Ended December 31, 2018 2017 2016 Current income taxes: Federal $ (997) $ 997 $ — State — 10 — Total current income tax expense (benefit) (997) 1,007 — Deferred income taxes: Federal 43,143 (40,529) (5,737) State (1,950) 698 162 Total deferred income tax expense (benefit) 41,193 (39,831) (5,575) Total income tax expense (benefit) $ 40,196 $ (38,824) $ (5,575) The actual income tax expense (benefit) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21%, 35% and 35% for 2018, 2017 and 2016, respectively, as follows: For the Year Ended December 31, 2018 2017 2016 Expected tax expense (benefit) at federal statutory rate $ 39,208 $ 3,870 $ (18,428) State income tax expense (benefit), net of federal benefit (3,360) 460 105 Pass-through entities (1) — — 12,499 Incentive unit compensation 2,893 — — Stock-based compensation (1,070) — — Valuation allowance 1,820 — 234 Change in tax rate (2) — (43,431) — Change in prior period estimates 24 315 — Other 681 (38) 15 Total income tax expense (benefit) $ 40,196 $ (38,824) $ (5,575) (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 Act. The components of net deferred income tax liabilities are as follows: Components of net deferred income tax liabilities: 2018 2017 Deferred income tax assets: Net operating loss Carryforwards $ 47,609 $ 29,866 Disallowed interest carryforwards 9,992 — Minimum tax credit Carryforward — 997 Asset retirement obligation 1,796 3,311 Derivatives — 16,903 Other 3,860 2,153 Total deferred income tax assets 63,257 53,230 Valuation allowance (1,820) — Net deferred income tax assets 61,437 53,230 Deferred income tax liabilities: Property, plant and equipment 158,868 124,700 Derivatives 15,300 — Total deferred income tax liabilities 174,168 124,700 Net deferred income tax liabilities $ 112,731 $ 71,470 Uncertain Income Tax Position. The Company must recognize the tax effects of any uncertain tax positions it may have 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, 2018 and expects no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2019. Tax Audits and Settlements. Generally, the Company's income tax years 2015 through 2018 remain open and subject to examination by federal and various state tax authorities which include Louisiana and Texas and certain other state taxing jurisdictions where the Company previously had 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, 2018, the Company had federal net operating loss (NOL) carryforwards of approximately $218.0 million. The federal NOL carryforwards generated prior to 2018 expire in 2036 and 2037. The 2018 federal NOL carryforward of $65.9 million has no expiration. The Company also had state tax carryforwards of approximately $28.8 million, which expire in 2036 through 2038. In addition, the Company had disallowed business interest carryforward of approximately $47.6 million, which can be carried forward indefinitely. The Company recorded a valuation allowance of approximately $1.8 million against its deferred tax assets related to state tax attributes due to the NLA Divestiture. The Company recorded no other valuation allowance 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, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 18. Commitments and Contingencies Litigation & Environmental We are party to various ongoing and potential 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, 2018 and December 31, 2017. 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. 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 collected by us during 2018. In January 2019, putative class action lawsuits in U.S. District Courts for the District of Delaware and Southern District of New York were filed against us and other defendants. The lawsuits generally allege various violations of the Securities Exchange Act of 1934 in connection with the disclosure contained in the joint proxy statement/prospectus filed in connection with the Merger. The lawsuits seek rescission of the Merger or rescissory damages and, in each case, attorney's fees, costs and interest. We intend to vigorously defend these claims. Klein v. Graham, et al. : On August 2, 2018, James M. Klein filed a derivative action in the Delaware Court of Chancery against seven of the Company’s directors and one of its former directors (the “Director Defendants”), NGP Energy Capital Management, LLC, CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), and (as a nominal defendant only) the Company. The complaint asserts claims relating to the Company’s entry into a Preferred Stock Purchase Agreement with the Carlyle Investor, dated May 10, 2017. The lawsuit seeks monetary damages and attorneys’ fees. The Company believes the claims are entirely without merit and intends to vigorously defend against them. On October 2, 2018, a stipulation of dismissal without prejudice was granted as it relates to Messrs. Clarkson and Sims. From time to time, we could be liable for environmental claims arising in the ordinary course of business. We did not record environmental obligations at December 31, 2018 and at December 31, 2017. Lease Obligations We executed two office leases during the year ended December 31, 2018. In June 2018, we executed a new lease for corporate office space that has escalating payments. The commencement date was December 1, 2018 and the lease terminates on December 31, 2026. In August 2018, we executed a new lease for our Fort Worth office with a start date of October 1, 2018 and terminating on September 30, 2021, with a penalty-free early termination clause after two years. Total office lease expense for the year ended December 31, 2018, 2017 and 2016 was $0.8 million, $1.0 million and $0.9 million. 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 Shale. 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. Our obligations under the contract ended in December 2018. 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. We have entered into drilling services agreements with varying terms, all of which have contractual terms of less than one year. We have entered into compressor rental agreements, which have contractual terms of 13 months or less, after which they can be terminated with notice. Total compressor and equipment rental expense incurred in 2018, 2017 and 2016 was $5.4 million, $2.0 million and $0.6 million, respectively. The table below reflects our minimum commitments as of December 31, 2018: 2019 2020 2021 2022 2023 Office Leases $ 2,399 $ 2,435 $ 2,398 $ 2,216 $ 2,251 Dedicated Fracturing Fleet Services Agreement — — — — Sand Mine Equipment — — — Compressors 4,143 3,991 3,859 2,724 902 Total $ 32,597 $ 9,862 $ 6,257 $ 4,940 $ 3,153 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 $0.5 million and $0.4 million during the years ended December 31, 2018 and 2017, respectively.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2018
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 (in thousands except per share amounts). 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 Second Third Fourth Quarter Quarter Quarter Quarter (1) For the Year Ended December 31, 2018 Revenues $ 218,757 $ 225,413 $ 259,490 $ 243,726 Operating income (loss) (100,053) 101,370 122,776 $ 88,196 Net income (loss) available to WRD (115,774) (14,094) 11,523 $ 264,853 Preferred stock dividends 7,389 7,961 6,756 6,756 Net income (loss) available to common stockholders (123,163) (22,055) 3,534 228,986 Basic earnings (loss) per share $ (1.24) $ (0.22) $ 0.04 $ 1.92 Diluted earnings (loss) per share $ (1.24) $ (0.22) $ 0.04 $ 1.92 For the Year Ended December 31, 2017 Revenues $ 54,292 $ 70,173 $ 122,486 $ 180,236 Operating income 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 (loss) per share $ 0.22 $ 0.28 $ (0.17) $ 0.06 Diluted earnings (loss) per share $ 0.22 $ 0.28 $ (0.17) $ 0.06 (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	12 Months Ended
	Dec. 31, 2018
Extractive Industries
Supplemental Oil and Gas Information	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 CG&A, a third-party independent reserve. 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, 2018 2017 2016 Oil ($/Bbl) West Texas Intermediate (1) $ 65.56 $ 51.34 $ 42.75 NGL ($/Bbl) West Texas Intermediate (1) $ 65.56 $ 51.34 $ 42.75 Natural Gas ($/Mmbtu) Henry Hub (2) $ 3.10 $ 2.98 $ 2.48 (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, 2018, 2017 and 2016, respectively: For the Year Ended December 31, 2018 Oil Gas NGL Equivalent Proved developed and undeveloped reserves: Beginning of the year 282,798 683,808 57,550 454,315 Extensions, discoveries and additions 81,174 129,962 16,377 119,211 Purchase of minerals in place 520 727 116 757 Sales of minerals in place (1,272) (393,057) (398) (67,180) Production (12,585) (21,531) (2,143) (18,316) Revision of previous estimates (65,369) (21,736) (13,747) (82,737) End of year 285,266 378,173 57,755 406,050 Proved developed reserves: Beginning of year 65,023 221,517 12,553 114,495 End of year 66,398 88,936 14,135 95,356 Proved undeveloped reserves: Beginning of year 217,775 462,291 44,997 339,820 End of year 218,868 289,237 43,620 310,694 For the Year Ended December 31, 2017 Oil Gas NGL Equivalent 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 Gas NGL Equivalent 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 Noteworthy amounts included in the categories of proved reserve changes in the above tables include: · During 2018, extensions, discoveries and additions increased proved reserves by 119,211 MBoe. These increases were partially offset by sales of minerals in place related to the North Louisiana Divestiture, which reduced proved reserves by 67,180 Mboe and production reducing proved reserves by 18,316 MBoe. We also had downward revisions of 82,737 Mboe, of which 86,953 MBoe were performance related partially offset by 4,216 MBoe related to commodity price increases. · During 2017, extensions, discoveries and additions increased proved reserves by 20,313 MBoe and 142,246 MBoe related to North Louisiana and Eagle Ford Shale, 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 North Louisiana and Eagle Ford Shale, 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. See Note 3- "Acquisitions and Divestitures" 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 (in thousands): For the Year Ended December 31, 2018 2017 2016 Future cash inflows $ 21,269,502 $ 16,967,369 $ 4,434,117 Future production costs (3,440,203) (3,305,941) (1,220,067) Future development costs (5,168,271) (4,008,916) (1,146,632) Future income tax expense (2,398,612) (1,814,510) (442,285) Future net cash flows for estimated timing of cash flows 10,262,416 7,838,002 1,625,133 10% annual discount for estimated timing of cash flows (6,144,980) (4,994,097) (1,082,092) Standardized measure of discounted future net cash flows $ 4,117,436 $ 2,843,905 $ 543,041 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, 2018 (in thousands): For the Year Ended December 31, 2018 2017 2016 Beginning of year $ 2,843,905 $ 543,041 $ 451,930 Sale of oil and natural gas produced, net of production costs (822,471) (351,031) (104,596) Purchase of minerals in place 4,313 507,095 188,317 Sales of minerals in place (319,858) — — Extensions and discoveries 1,829,564 1,595,385 168,796 Changes in income taxes, net (277,050) (488,484) (206,817) Changes in prices and costs 1,380,323 398,713 (57,034) Previously estimated development costs incurred 67,575 49,977 15,067 Net changes in future development costs (13,317) (87,375) 11,985 Revisions of previous quantities (1,057,523) 653,567 3,943 Accretion of discount 323,927 74,999 103,000 Change in production rates and other 158,048 (51,982) (31,550) End of year $ 4,117,436 $ 2,843,905 $ 543,041 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 (in thousands). For the Year Ended December 31, 2018 2017 2016 Evaluated oil and natural gas properties $ 2,764,875 $ 2,265,525 $ 1,144,857 Unevaluated oil and natural gas properties 693,023 734,203 428,991 Accumulated depletion, depreciation and amortization (498,811) (362,406) (196,567) Total $ 2,959,087 $ 2,637,322 $ 1,377,281 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, 2018 2017 2016 Property acquisition costs, proved $ 4,422 $ 269,429 $ 230,910 Property acquisition costs, unproved 85,863 386,515 235,652 Exploration and extension well costs 11,979 16,076 72,875 Development 927,985 795,273 63,006 Total $ 1,030,249 $ 1,467,293 $ 602,443

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 21. Subsequent Events Quarterly Preferred Stock Dividend Merger with Chesapeake In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake. Following the completion of the Merger on February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor to WildHorse Development, was a wholly owned subsidiary of Chesapeake. On February 1, 2019, we paid our financial advisors $23.1 million of advisory fees, which were contingent upon the closing of the merger with Chesapeake. The contingent fee was not deemed probable at December 31, 2018. On February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor by merger to WildHorse, entered into a sixth amendment (the "Sixth Amendment") to its Credit Agreement. Among other things, the Sixth Amendment (i) amended the merger covenant and the definition of change of control to permit the WildHorse Merger and (ii) permits borrowings under the Credit Agreement to be used to redeem or repurchase the 2025 Senior Notes so long as certain conditions are met. On February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor by merger to WildHorse, and Brazos Valley Longhorn Finance Corp., a Delaware corporation ("BVL Finance Corp.") and wholly owned subsidiary of the Company, entered into a fourth supplemental indenture (the "Fourth Supplemental Indenture") to the 2025 Indenture. Pursuant to the Fourth Supplemental Indenture, (i) the Brazos Valley Longhorn, L.L.C. assumed the rights and obligations of WildHorse as issuer under the 2025 Indenture and (ii) BVL Finance Corp. was named as a co-issuer of the 2025 Senior Notes under the 2025 Indenture. If the 2025 Senior Notes are downgraded within 90 days after the consummation of the WildHorse Merger (which constitutes a "Change of Control" under the 2025 Indenture), the 2025 Indenture requires the Company (or a third party, in certain circumstances) to make an offer to repurchase the 2025 Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, within 30 days of such downgrade. If any holder of 2025 Senior Notes accepts such offer, the Company may (subject to the terms and conditions thereof) fund the purchase price with loans under the Credit Agreement, use cash on hand, issue debt securities or use other sources of liquidity to fund such repurchase.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Initial Public Offering and Corporate Reorganization	Initial Public Offering and Corporate Reorganization 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, exploration, development and production of oil, natural gas and NGL resources. WHR II, Esquisto II, Acquisition Co., WHR Eagle Ford LLC (“WHR EF”), Burleson Sand LLC (“Burleson Sand”) and WHCC Infrastructure LLC (“WHCC”) are wholly owned subsidiaries of the Company as of December 31, 2018. WildHorse Resources Management Company, LLC (“WHRM”) is a wholly owned subsidiary of WHR II. Esquisto II 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. 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.
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 have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public. 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. Our consolidated and combined financial statements include our accounts and those of our subsidiaries. Restricted cash was previously presented as a component of cash flows from investing activities on the consolidated and combined statements of cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals due to the adoption of a new accounting standard. 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.
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, natural gas and NGL 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 income 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 Historically, restricted cash consisted of certificates of deposit in place to collateralize letters of credit. The letters of credit were required as part of normal business operations. The certificates of deposit were in place for a period greater than 12 months and were considered noncurrent. We had no restricted cash at December 31, 2018 and 2017.
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. Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed. We have excluded capitalized costs of $98.1 million at December 31, 2018. 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 (in thousands): For Year Ended December 31, 2018 2017 2016 Balance, beginning of period $ — $ 7,064 $ 15,198 Additions to capitalized exploratory well costs pending the determination of proved reserves — — 60,847 Reclassifications to wells, facilities and equipment based on the determination of proved reserves — (7,064) (68,981) Capitalized exploratory well costs charged to expense — — — Balance, end of period $ — $ — $ 7,064 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 $10.5 million, $20.8 million and $3.1 million as exploration expense for unproved oil and gas properties for the years ended December 31, 2018, 2017 and 2016, respectively. 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
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 Cawley, Gillespie & Associates, Inc. ("CG&A"), a third-party independent reserve engineer. 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 sand mine, saltwater disposal wells, 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, 2018, 2017 and 2016, we recorded $5.9 million, $3.1 million and $0.1 million in capitalized interest, respectively.
Properties Acquired in Business Combinations	Properties Acquired in Asset Acquisitions and Business Combinations For asset acquisitions, the purchase price recorded at cost and is allocated to identifiable assets on a relative fair value basis. Therefore, we would need to determine the fair value of the assets at acquisition. 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 from Contracts with Customers Our revenues are derived through the sale of our hydrocarbon production, specifically the sale of crude oil, natural gas and NGLs. On January 1, 2018 the Company adopted ASC 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) to all contracts that were not completed as of January 1, 2018 using the cumulative effect transition method. The cumulative effect of adopting the standard was recognized through an adjustment to opening accumulated earnings. The new revenue 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.” We review our contracts through the five-step model at inception, and as any new contracts are executed or existing contracts are modified, to determine when to recognize revenue. We expect the overall impact to net income to be immaterial on an ongoing basis. Previous periods have not been revised or adjusted and reflect the revenue standard in effect for those periods. Under the previous revenue recognition standard, revenues were recognized when the product was delivered at a fixed and determinable price, title transferred and collectability was reasonably assured and evidenced by a contract. Crude oil sales contracts We have performance obligations under our crude oil sales contracts to deliver barrels of oil, where each barrel of oil is considered to be its own performance obligation under the new revenue standard. Volumes are generally not predetermined and pricing for the crude oil is index-based, adjusted for location and other economic factors. We recognize revenue from the sale of our crude oil at a point in time, when we transfer control of the crude oil to our purchaser, which occurs when the oil passes through our facilities (typically a tank battery or our third-party contracted trucks) into our purchaser’s receiving equipment (typically a truck or their pipeline). Once the crude oil has been delivered, we have fulfilled our obligation and we no longer have the ability to direct the use of, or obtain any of the remaining benefits from that crude oil. Sales of crude oil are presented on the “Oil sales” line item of our statement of operations. The adoption of the new revenue standard did not result in any material changes to the accounting or presentation of oil sales. Natural gas sales contracts Our natural gas contracts stipulate that we deliver unprocessed natural gas to a contractually specified delivery point. Once the natural gas enters our customer’s facilities, it may be compressed, dehydrated, treated, separated into residue gas (predominately methane) and NGLs, or otherwise processed. For a majority of our natural gas sales contracts, the Company transfers control of the natural gas (which could include both residue gas and NGLs) to our customer upon delivery into their facilities and we recognize revenue at that point in time. Our performance obligation within these contracts is to deliver unprocessed natural gas. Once delivered, we have fulfilled our obligation and our customers have full control over the use, sale or disposition of the gas. Any charges assessed to us by our customer, including but not limited to gathering, processing, compression, treating and dehydration are considered to be a reduction to the transaction price because we did not receive a distinct good or service from the customer. Services are not deemed to be provided to us because the related activities occur after we transfer control of the gas to our customer. Prior to the adoption of the new revenue standard, these charges were reported within “Gathering, processing and transportation” expense in our statement of operations, while these costs are now being netted against revenues. For the other portion of our natural gas sales contracts, our contracts are structured such that both the customer and the Company have shared contractual control over the natural gas. Contractual terms dictate that payment to us is based on actual extracted volumes of NGLs/residue gas. Further, the contracts stipulate that a portion of that processed gas is retained by our customer as compensation for their services, thereby incentivizing the customer to process our gas and operate their facilities efficiently in our best interest. Under these contracts, the value associated with the volumes our customer retains and any charges assessed by our customer are recognized on our “Gathering, processing and transportation” expense line item. This is because the gas is contractually controlled jointly by both us and our customer until our performance obligation is fulfilled at the tailgate of our customer’s plant (once processing has been completed). Our performance obligation under these contracts is to sell the extracted NGLs and residue gas. We recognize revenue at a point in time (at the plant tailgate) when we have fulfilled our performance obligation. Prior to the adoption of the new revenue standard, we did not recognize the volumes retained by our customer as an expense and we reported revenues net of the volumes they retained. Residue gas contracts In certain of the natural gas sales contracts discussed above, the residue gas separated during plant processing is not sold to the processor but is instead redelivered back to us at the tailgate of the plant. We directly market these volumes to third parties using index-based natural gas prices and utilize our pipeline capacity (under our transportation agreements) to deliver these volumes from the plant tailgate to market. Our performance obligation in our residue gas contracts is the delivery of residue gas. Control over residue gas transfers upon delivery, at which point we have fulfilled our performance obligation and can recognize revenue. Performance obligations fulfilled in a prior period We record revenue in the month oil or natural gas volumes are delivered to the customer, based on estimated production, prices and revenue deductions. Any variances between our estimates and the actual amounts received are generally recorded one month after delivery for operated oil sales, two months after delivery for operated natural gas and NGL sales and three months after delivery for non-operated oil, natural gas and NGL sales. Disaggregation of revenue The new revenue standard requires that we disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Our statement of operations disaggregates revenue to reflect pricing realities present in our contracts with our customers. The terms of our natural gas sales contracts stipulate that the pricing we receive for our unprocessed natural gas will be based on the volumes of lower value natural gas and higher value NGLs present in the unprocessed natural gas we deliver. Fees assessed by our customers (that reduce revenue) are allocated between gas and NGLs on a volumetric basis or based upon the nature of the fee. Contributions in aid of construction 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. These long-term assets are amortized over the period of the benefit and are presented as a reduction to natural gas and NGL revenue or as a gathering, processing and transportation expense. Prior to the adoption of the new revenue standard, these assets were recorded to our “Oil and gas properties” line item on the balance sheet and depleted using the units of production method. As depicted below, we adjusted the balance sheet and accumulated earnings for the cumulative effect of this accounting change. The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of the new revenue standard is as follows (in thousands): At December 31, Adjustments for At January 1, 2017 ASC 606 2018 Assets: Oil and gas properties $ 2,999,728 $ (4,041) $ 2,995,687 Accumulated depreciation, depletion and amortization (368,245) 371 (367,874) Other non-current assets — 3,978 3,978 Liabilities: Deferred tax liabilities $ 71,470 $ 67 $ 71,537 Stockholders’ Equity: Accumulated earnings (deficit) $ 25,773 $ 243 $ 26,016 Other topics Production Imbalances - 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. Contract assets - The new revenue standard requires certain disclosure around contract assets. Contract assets are rights to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditional on something other than the passage of time. We have an unconditional right to payment upon completion of our performance obligations and have therefore recorded no contract assets as of December 31, 2018. Unsatisfied performance obligations - We have no unsatisfied performance obligations under our contracts. The majority of our contracts do not have stated volumes and we consider our performance obligations to be satisfied upon transfer of control of the commodity. In our remaining contracts where we are obligated to deliver a stated volume, all volumes are delivered in the period and we do not have any unsatisfied performance obligations under those contracts at the end of a period. Other Income - During the period, we owned the Oakfield gathering system, substantial fresh water supply and storage, a saltwater disposal well and several compressors. Though the Oakfield gathering system, saltwater disposal well and compressors were sold to Tanos Energy Holdings III, LLC (“Tanos”) as part of the NLA Divestiture (see Note 3 - "Acquisitions and Divestitures"), these assets were used during the period in the operations of our wells. Non-operators who own a portion of our wells are billed for the use of these assets, utilizing rates based on industry-accepted joint interest accounting rules and market conditions. We report income from this source as “Other income” on our statement of operations in accordance with accounting guidance on collaborative arrangements. Operating expenses related to these activities are recorded to the “Other operating (income) expense” line item on the statement of operations. Prior to the adoption of the new revenue standard, income net of expenses from saltwater disposal wells and compressors were recorded within lease operating expense and income net of expenses for the Burleson water supply and storage assets were recorded within other income. In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement, balance sheet and statement of cash flows was as follows (in thousands): For the Year Ended December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Revenues: Oil sales $ 843,244 $ 843,329 $ (85) Natural gas sales 60,129 64,896 (4,767) NGL sales 41,961 51,052 (9,091) Other Income 2,052 1,861 191 Operating expenses: Lease operating expenses 61,620 63,043 (1,423) Gathering, processing and transportation 9,856 22,703 (12,847) Depreciation, depletion and amortization 296,685 297,295 (610) Other operating expense 1,064 459 605 Income before income taxes 186,704 186,180 524 Income tax expense (40,196) (40,083) (113) Net income 146,508 146,097 411 At December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,457,897 $ 3,463,857 $ (5,960) Accumulated depreciation, depletion and amortization (518,054) (519,035) 981 Other non-current assets 17,250 11,439 5,811 Liabilities: Deferred tax liabilities 112,731 112,551 180 Stockholders' Equity Accumulated earnings 136,773 137,785 (1,012) For the Year Ended December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ 146,508 $ 146,097 $ 411 Depreciation, depletion and amortization 296,685 297,295 (610) Deferred income tax expense 41,193 41,080 113 Consideration paid to customers, net of amortization (1,817) — (1,817) Cash flows from investing activities: Additions to oil and gas properties (1,051,891) (1,053,811) 1,920
Incentive Units	Incentive Units For details regarding incentive units, 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 $0.2 million and $0.1 million at December 31, 2018 and 2017, respectively.
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. For our forward commodity contracts that meet the definition of a derivative, we have elected the normal purchases and normal sales scope exclusion, because we believe it is probable that physical delivery of the product will occur under the contract and we do not intend on net settling the contract. Therefore, all activity under these contracts was recorded as revenue in our consolidated financial statements. 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 or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in Other income (expense) in our Consolidated and Combined Statement of Operations. 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.
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For Year Ended December 31, 2018 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 48,717 $ 12,246 $ 7,152 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (82,358) 134,589 (4,492) (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (1,247) (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	New Accounting Standards Definition of a Business In January 2017, the Financial Accounting Standards Board (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. The Company adopted this guidance on January 1, 2018 on a prospective basis 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. 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. 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. Leases In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, which requires classification of leases as finance or operating. The classification is based on criteria that are similar to the current lease accounting guidance. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. In July 2018, the FASB issued targeted improvements to the new leasing standard, which now allows entities the option to use the January 1, 2019 effective date as the date of initial application (“the effective date method”). As a result, comparative periods will not require adjustment because only contracts existing as of January 1, 2019 are within the scope of the new standard. The Company adopted the standard using the effective date method on January 1, 2019. Further, the new standard allows lessees to adopt a package of practical expedients upon transition to the new standard, whereby contracts existing as of January 1, 2019 will not require reassessment under the new definition of a lease or new lease classification criteria. Therefore, a contract existing on January 1, 2019 that did not meet the definition of a lease under the old standard, will not be accounted for or reported as a lease under the new standard. Effectively, the current identification and classification will remain for those leases (under the new standard) unless those leases are modified or require reassessment under the new standard. The Company has made this accounting policy election beginning January 1, 2019 . For leases with a term of 12 months or less (i.e. a short-term lease), a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize right-of-use assets and lease liabilities. If a lessee makes this election, it should generally recognize lease expense for such leases on a straight-line basis over the lease term and short-term lease costs must be disclosed for each period. The Company has made this accounting policy election for all classes of assets beginning January 1, 2019 . The new standard provides a scope exclusion for the rights to use land easements related to oil and gas activities, for which many of our land easement will qualify. Additionally, the standard allows a practical expedient not to reassess whether land easements existing on January 1, 2019 meet the definition of a lease under the new standard if they were not accounted for as leases under the current standard. The Company has made this accounting policy election beginning January 1, 2019. The Company is a lessee under various agreements for office space, compressors and other equipment. Though we are finalizing the implementation of certain processes to monitor and track all lease information, we anticipate leases as recognized under the new standard will create right-of-use assets and initial lease liabilities between $35 million and $65 million on our consolidated balance sheet. 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

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Impact of adoption of revenue standard
Schedule of Net Changes Capitalized Exploratory Costs	The following table reflects the net changes in capitalized exploratory well costs for the periods indicated (in thousands): For Year Ended December 31, 2018 2017 2016 Balance, beginning of period $ — $ 7,064 $ 15,198 Additions to capitalized exploratory well costs pending the determination of proved reserves — — 60,847 Reclassifications to wells, facilities and equipment based on the determination of proved reserves — (7,064) (68,981) Capitalized exploratory well costs charged to expense — — — Balance, end of period $ — $ — $ 7,064
Schedule of Supplemental Cash Flow Information	Supplemental cash flow for the periods presented (in thousands): For Year Ended December 31, 2018 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 48,717 $ 12,246 $ 7,152 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (82,358) 134,589 (4,492) (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (1,247) (847) (5,175)
Accounting Standards Update 2014-09
Impact of adoption of revenue standard
Summary of Impact of Adoption of Accounting Standards	XBRL-Only Content Section The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of the new revenue standard is as follows (in thousands): At December 31, Adjustments for At January 1, 2017 ASC 606 2018 Assets: Oil and gas properties $ 2,999,728 $ (4,041) $ 2,995,687 Accumulated depreciation, depletion and amortization (368,245) 371 (367,874) Other non-current assets — 3,978 3,978 Liabilities: Deferred tax liabilities $ 71,470 $ 67 $ 71,537 Stockholders’ Equity: Accumulated earnings (deficit) $ 25,773 $ 243 $ 26,016 In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement, balance sheet and statement of cash flows was as follows (in thousands): For the Year Ended December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Revenues: Oil sales $ 843,244 $ 843,329 $ (85) Natural gas sales 60,129 64,896 (4,767) NGL sales 41,961 51,052 (9,091) Other Income 2,052 1,861 191 Operating expenses: Lease operating expenses 61,620 63,043 (1,423) Gathering, processing and transportation 9,856 22,703 (12,847) Depreciation, depletion and amortization 296,685 297,295 (610) Other operating expense 1,064 459 605 Income before income taxes 186,704 186,180 524 Income tax expense (40,196) (40,083) (113) Net income 146,508 146,097 411 At December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,457,897 $ 3,463,857 $ (5,960) Accumulated depreciation, depletion and amortization (518,054) (519,035) 981 Other non-current assets 17,250 11,439 5,811 Liabilities: Deferred tax liabilities 112,731 112,551 180 Stockholders' Equity Accumulated earnings 136,773 137,785 (1,012) For the Year Ended December 31, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ 146,508 $ 146,097 $ 411 Depreciation, depletion and amortization 296,685 297,295 (610) Deferred income tax expense 41,193 41,080 113 Consideration paid to customers, net of amortization (1,817) — (1,817) Cash flows from investing activities: Additions to oil and gas properties (1,051,891) (1,053,811) 1,920

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Acquisition-Related Costs Included in General and Administrative Expenses	Acquisition-related costs 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, 2018 2017 2016 $ 1,117 $ 4,348 $ 553
APC/KKR Acquisitions
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 $ 533,002 Common stock 60,754 Total consideration $ 593,756 Final Purchase Price Allocation Proved oil and gas properties $ 264,467 Unproved oil and gas properties 333,778 Accounts receivable 60 Asset retirement obligations (2,500) Accrued liabilities (2,049) Total identifiable net assets $ 593,756
Summary of Unaudited Pro Forma Financial Information	For the 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 North 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 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
Summary of Unaudited Pro Forma Financial Information	For Year Ended December 31, 2016 Revenues $ 176,082 Net loss $ (34,894) Basic and diluted earnings per unit n/a
November and Rosewood Acquisitions
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 November Oil and gas properties $ 19,626 $ 29,973

Fair Value Measurements of Fi_2

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	Fair Value Measurements at December 31, 2018 Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 72,710 $ — $ 72,710 Liabilities: Commodity derivatives $ — $ 508 $ — $ 508 Fair Value Measurements at December 31, 2017 Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 2,422 $ — $ 2,422 Liabilities: Commodity derivatives $ — $ 76,750 $ — $ 76,750

Risk Management and Derivativ_2

Risk Management and Derivative and Other Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure
Schedule of Derivative Contracts	The following derivative contracts were in place at December 31, 2018: 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 6,652,369 4,511,681 Weighted-average fixed price $ 54.45 $ 53.49 Put options: Volume (Bbls) 1,749,757 — Weighted-average floor price $ 53.83 $ — Weighted-average put premium $ (5.43) $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 6,425,146 4,846,020 Weighted-average fixed price $ 2.79 $ 2.76
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification	Asset Derivatives Liability Derivatives (in thousands) (in thousands) Type Balance Sheet Location 2018 2017 2018 2017 Commodity contracts Short-term derivative instruments $ 54,131 $ 2,336 $ 508 $ 58,074 Netting arrangements Short-term derivative instruments — — — — Net recorded fair value $ 54,131 $ 2,336 $ 508 $ 58,074 Commodity contacts Long-term derivative instruments $ 18,579 $ 86 $ — $ 18,676 Netting arrangements Long-term derivative instruments — — — — Net recorded fair value $ 18,579 $ 86 $ — $ 18,676
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, 2018, 2017 and 2016 (in thousands): Statements of For the Year Ended December 31, Operations Location 2018 2017 2016 Commodity derivative contracts Gain (loss) on derivative instruments $ 35,393 $ (55,483) $ (26,771)

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2018
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following (in thousands): At December 31, 2018 2017 Oil, gas and NGL sales $ 70,900 $ 67,584 Joint interest billings 17,491 9,467 Severance tax 1,352 171 Derivative receivable 308 — North Louisiana Settlement receivable — 5,955 Environmental remediation 1,511 — Other current receivables 196 1,026 Allowance for doubtful accounts (200) (100) Total $ 91,558 $ 84,103
Schedule of Allowance for Doubtful Accounts Activity	The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): 2018 2017 2016 Balance at beginning of period $ 100 $ 100 $ 50 Charged to costs and expenses 100 — 50 Balance at end of period $ 200 $ 100 $ 100

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Payables And Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consist of the following (in thousands): At December 31, 2018 2017 Capital expenditures $ 80,897 $ 162,260 Preferred stock cash dividends 4,479 — Deferred rent — 410 Lease operating expense 6,604 5,796 General and administrative 4,335 1,642 Severance and ad valorem taxes 5,283 3,463 Interest expense 20,122 17,177 Derivative payable 1,746 5,281 Income taxes — 991 Other accrued liabilities 1,167 2,932 Total $ 124,633 $ 199,952

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 (in thousands): For the Year Ended December 31, 2018 2017 Asset retirement obligations at beginning of period $ 14,557 $ 11,033 Accretion expense 573 713 Liabilities incurred 743 3,137 Liabilities settled — — Revisions 70 (326) Disposition of wells and gathering system (7,627) — Asset retirement obligations at end of period 8,316 14,557 Less: current portion 90 90 Asset retirement obligations – long-term $ 8,226 $ 14,467

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Our debt obligations consisted of the following (in thousands): At December 31, Debt Obligation 2018 2017 WRD revolving credit facility $ 504,000 $ 286,353 2025 Senior Notes (as defined below) (1) 700,000 500,000 Unamortized net discounts - 2025 Senior Notes (782) (4,914) Unamortized debt issuance costs - 2025 Senior Notes (11,842) (10,843) Total long-term debt $ 1,191,376 $ 770,596 The estimated fair value of this fixed-rate debt was $661.5 million and $511.3 million at December 31, 2018 and 2017, respectively. The estimated fair values are 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 2018 WRD revolving credit facility $ 1,300,000
Schedule of Debt Instrument Pricing Based on Borrowing Base Utilization	Borrowing Base Utilization LIBOR Margin Base Rate Margin Commitment Fee >= 90% 250.0 bps 150.0 bps 50.0 bps >= 75%; < 90% 225.0 bps 125.0 bps 50.0 bps >=50%; < 75% 200.0 bps 100.0 bps 50.0 bps >= 25%; < 50% 175.0 bps 75.0 bps 37.5 bps < 25% 150.0 bps 50.0 bps 37.5 bps
Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations	At December 31, Credit Facility 2018 2017 2016 WRD revolving credit facility 4.06 % 3.60 % 3.52 % WHR II revolving credit facility terminated December 2016 n/a n/a 3.03 % Esquisto - revolving credit facility terminated December 2016 n/a n/a 2.84 % Esquisto - revolving credit facility terminated January 2016 n/a n/a 2.97 % Esquisto - Second lien terminated in January 2016 n/a n/a 9.50 %
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 (in thousands): At December 31, 2018 2017 WRD revolving credit facility Current $ 1,823 $ 1,203 Long-term 3,592 3,573 6.875% senior unsecured notes, due February 2025 11,842 10,843 Total $ 17,257 $ 15,619

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2018
Temporary Equity [Abstract]
Schedule of Preferred Stock	Series A Perpetual Convertible Preferred Stock (in thousands) Balance at December 31, 2016 $ — Issue 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 Paid-in-kind dividend 2,243 Beneficial conversion feature ("BCF") (1,872) Amortization of BCF 1,872 Balance at December 31, 2018 $ 447,726
Schedule of Preferred Stock Dividends	Period Covered Date of Record From To Cash Dividends Paid Payment Date (in millions) April 15, 2018 February 1, 2018 April 30, 2018 $ April 30, 2018 July 15, 2018 May 1, 2018 July 31, 2018 $ July 31, 2018 October 15, 2018 August 1, 2018 October 31, 2018 $ October 31, 2018

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Summary of Changes in Common Shares Issued	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 Restricted common shares issued 1,076,165 Restricted common shares forfeited (63,768) Repurchase of vested restricted shares (2) (355,819) Balance, December 31, 2018 101,793,855 (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 $6.9 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. 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.
Schedule Of Advances And Payments Of Promissory Note Advances Table [Text Block]	The table below summarizes advances and payments of the promissory note advances for the year ended December 31, 2016 (in thousands): Principal Interest Total 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, 2018
Earnings Per Share [Abstract]
Schedule of Calculation of Earnings (Loss) Per Share	For the Year Ended December 31, 2018 (1) 2017 (2) 2016 (3) Numerator: Net income (loss) available to WRD $ 146,508 $ 49,880 $ (10,397) Less: Preferred stock dividends 28,862 13,146 — Less: Undistributed earnings allocated to participating securities 30,344 5,612 — Net income (loss) available to common stockholders $ 87,302 $ 31,122 $ (10,397) Denominator: Weighted-average common shares outstanding (in thousands) 99,498 96,324 91,327 Basic EPS $ 0.88 $ 0.32 $ (0.11) Diluted EPS $ 0.88 $ 0.32 $ (0.11) (1) The Company used the two-class method for both basic and diluted EPS. For the year ended December 31, 2018, 775 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the for the year ended December 31, 2018, 32,363 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method. (2) The Company used the two-class method for both basic and diluted EPS. For the year 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 year 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. The Company used the two-class method for both basic and diluted EPS. For the year ended December 31, 2016, restricted shares were excluded from the calculation of diluted EPS due to their antidilutive effect as we were in a loss position for the period

Long Term Incentive Plans (Tabl

Long Term Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Restricted Common Stock Awards Granted Under 2016 LTIP	Weighted-Average Number of Grant Date Fair Shares Value per Share (1) Restricted common shares outstanding at January 1, 2016 — $ — Granted (2) 353,334 $ 14.50 Restricted common stock 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 stock outstanding at December 31, 2017 1,897,790 $ 13.95 Granted (2) 1,076,165 $ 25.57 Forfeited (63,768) $ 16.45 Vested (1,069,933) $ 15.66 Restricted common stock outstanding at December 31, 2018 1,840,254 $ 19.66 (1) Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards. 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. The aggregate grant date fair value of restricted common share awards granted in 2018 was $27.5 million based on grant date market price ranging from $18.14 to $27.07 per share. Our awards have contractual vesting periods between one and three years.

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Summary of Major Customers	For the Year Ended December 31, Major Customers 2018 2017 2016 Energy Transfer Equity, L.P. and subsidiaries 49 % 56 % 63 % Koch Industries, Inc. 19 % 4 % n/a Royal Dutch Shell plc and subsidiaries 18 % 21 % 12 % Cima Energy LTD n/a n/a 15 %

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Components of Income Tax Benefit (Expense)	The components of income tax expense (benefit) are as follows (in thousands): For the Year Ended December 31, 2018 2017 2016 Current income taxes: Federal $ (997) $ 997 $ — State — 10 — Total current income tax expense (benefit) (997) 1,007 — Deferred income taxes: Federal 43,143 (40,529) (5,737) State (1,950) 698 162 Total deferred income tax expense (benefit) 41,193 (39,831) (5,575) Total income tax expense (benefit) $ 40,196 $ (38,824) $ (5,575)
Schedule of Effective Income Tax Rate Reconciliation	For the Year Ended December 31, 2018 2017 2016 Expected tax expense (benefit) at federal statutory rate $ 39,208 $ 3,870 $ (18,428) State income tax expense (benefit), net of federal benefit (3,360) 460 105 Pass-through entities (1) — — 12,499 Incentive unit compensation 2,893 — — Stock-based compensation (1,070) — — Valuation allowance 1,820 — 234 Change in tax rate (2) — (43,431) — Change in prior period estimates 24 315 — Other 681 (38) 15 Total income tax expense (benefit) $ 40,196 $ (38,824) $ (5,575) (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 Act.
Components of Net Deferred Income Tax Liabilities	Components of net deferred income tax liabilities: 2018 2017 Deferred income tax assets: Net operating loss Carryforwards $ 47,609 $ 29,866 Disallowed interest carryforwards 9,992 — Minimum tax credit Carryforward — 997 Asset retirement obligation 1,796 3,311 Derivatives — 16,903 Other 3,860 2,153 Total deferred income tax assets 63,257 53,230 Valuation allowance (1,820) — Net deferred income tax assets 61,437 53,230 Deferred income tax liabilities: Property, plant and equipment 158,868 124,700 Derivatives 15,300 — Total deferred income tax liabilities 174,168 124,700 Net deferred income tax liabilities $ 112,731 $ 71,470

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Summary of Minimum Commitments of Lease Obligations	The table below reflects our minimum commitments as of December 31, 2018: 2019 2020 2021 2022 2023 Office Leases $ 2,399 $ 2,435 $ 2,398 $ 2,216 $ 2,251 Dedicated Fracturing Fleet Services Agreement — — — — Sand Mine Equipment — — — Compressors 4,143 3,991 3,859 2,724 902 Total $ 32,597 $ 9,862 $ 6,257 $ 4,940 $ 3,153

Quarterly Financial Informati_2

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	First Second Third Fourth Quarter Quarter Quarter Quarter (1) For the Year Ended December 31, 2018 Revenues $ 218,757 $ 225,413 $ 259,490 $ 243,726 Operating income (loss) (100,053) 101,370 122,776 $ 88,196 Net income (loss) available to WRD (115,774) (14,094) 11,523 $ 264,853 Preferred stock dividends 7,389 7,961 6,756 6,756 Net income (loss) available to common stockholders (123,163) (22,055) 3,534 228,986 Basic earnings (loss) per share $ (1.24) $ (0.22) $ 0.04 $ 1.92 Diluted earnings (loss) per share $ (1.24) $ (0.22) $ 0.04 $ 1.92 For the Year Ended December 31, 2017 Revenues $ 54,292 $ 70,173 $ 122,486 $ 180,236 Operating income 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 (loss) per share $ 0.22 $ 0.28 $ (0.17) $ 0.06 Diluted earnings (loss) per share $ 0.22 $ 0.28 $ (0.17) $ 0.06 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 Info_2

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Extractive Industries
Weighted Average Benchmark Product Prices	For the Year Ended December 31, 2018 2017 2016 Oil ($/Bbl) West Texas Intermediate (1) $ 65.56 $ 51.34 $ 42.75 NGL ($/Bbl) West Texas Intermediate (1) $ 65.56 $ 51.34 $ 42.75 Natural Gas ($/Mmbtu) Henry Hub (2) $ 3.10 $ 2.98 $ 2.48 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. 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, 2018, 2017 and 2016, respectively: For the Year Ended December 31, 2018 Oil Gas NGL Equivalent Proved developed and undeveloped reserves: Beginning of the year 282,798 683,808 57,550 454,315 Extensions, discoveries and additions 81,174 129,962 16,377 119,211 Purchase of minerals in place 520 727 116 757 Sales of minerals in place (1,272) (393,057) (398) (67,180) Production (12,585) (21,531) (2,143) (18,316) Revision of previous estimates (65,369) (21,736) (13,747) (82,737) End of year 285,266 378,173 57,755 406,050 Proved developed reserves: Beginning of year 65,023 221,517 12,553 114,495 End of year 66,398 88,936 14,135 95,356 Proved undeveloped reserves: Beginning of year 217,775 462,291 44,997 339,820 End of year 218,868 289,237 43,620 310,694 For the Year Ended December 31, 2017 Oil Gas NGL Equivalent 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 Gas NGL Equivalent 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
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows (in thousands): For the Year Ended December 31, 2018 2017 2016 Future cash inflows $ 21,269,502 $ 16,967,369 $ 4,434,117 Future production costs (3,440,203) (3,305,941) (1,220,067) Future development costs (5,168,271) (4,008,916) (1,146,632) Future income tax expense (2,398,612) (1,814,510) (442,285) Future net cash flows for estimated timing of cash flows 10,262,416 7,838,002 1,625,133 10% annual discount for estimated timing of cash flows (6,144,980) (4,994,097) (1,082,092) Standardized measure of discounted future net cash flows $ 4,117,436 $ 2,843,905 $ 543,041
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, 2018 (in thousands): For the Year Ended December 31, 2018 2017 2016 Beginning of year $ 2,843,905 $ 543,041 $ 451,930 Sale of oil and natural gas produced, net of production costs (822,471) (351,031) (104,596) Purchase of minerals in place 4,313 507,095 188,317 Sales of minerals in place (319,858) — — Extensions and discoveries 1,829,564 1,595,385 168,796 Changes in income taxes, net (277,050) (488,484) (206,817) Changes in prices and costs 1,380,323 398,713 (57,034) Previously estimated development costs incurred 67,575 49,977 15,067 Net changes in future development costs (13,317) (87,375) 11,985 Revisions of previous quantities (1,057,523) 653,567 3,943 Accretion of discount 323,927 74,999 103,000 Change in production rates and other 158,048 (51,982) (31,550) End of year $ 4,117,436 $ 2,843,905 $ 543,041
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 (in thousands). For the Year Ended December 31, 2018 2017 2016 Evaluated oil and natural gas properties $ 2,764,875 $ 2,265,525 $ 1,144,857 Unevaluated oil and natural gas properties 693,023 734,203 428,991 Accumulated depletion, depreciation and amortization (498,811) (362,406) (196,567) Total $ 2,959,087 $ 2,637,322 $ 1,377,281
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	For the Year Ended December 31, 2018 2017 2016 Property acquisition costs, proved $ 4,422 $ 269,429 $ 230,910 Property acquisition costs, unproved 85,863 386,515 235,652 Exploration and extension well costs 11,979 16,076 72,875 Development 927,985 795,273 63,006 Total $ 1,030,249 $ 1,467,293 $ 602,443

Organization and Basis of Pre_2

Organization and Basis of Presentation - Additional Information (Details) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2019USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2018subsidiary
Organization And basis of presentation
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 offering costs		5
Net proceeds from initial public offering		393.4
Debt issuance cost		$ 2.9
Chesapeake | Wildhorse Resource Development Corporation | Subsequent Event
Organization And basis of presentation
Business acquisition, shares issued | shares	717,300,000
Cash paid	$ 381.1
Esquisto II
Organization And basis of presentation
Number of wholly owned subsidiaries | subsidiary			2

Organization and Basis of Pre_3

Organization and Basis of Presentation - Investment in Unconsolidated Affiliate (Details) $ in Thousands	Jul. 27, 2018USD ($)	Jul. 31, 2018USD ($)	Dec. 31, 2018USD ($)
Investment in unconsolidated affiliate
Cash capital contribution			$ 10,177
Line of Credit Facility, Collateral Fees		$ 0.4
Minimum range of investment value the entity deems as more than minor			more than 3 to 5 percent
Loss on equity investment			$ 676
Other income (expense)
Investment in unconsolidated affiliate
Loss on equity investment			700
Port of Corpus Christi Authority
Investment in unconsolidated affiliate
Lease term		20 years
Irrevocable Standby Letter of Credit
Investment in unconsolidated affiliate
Letter of credit outstanding	$ 47,500
Irrevocable Standby Letter of Credit | Port of Corpus Christi Authority
Investment in unconsolidated affiliate
Term of letter of credit	10 years
JWH
Investment in unconsolidated affiliate
Accrued capital contribution			1,900
JWH | Other
Investment in unconsolidated affiliate
Equity method investment			$ 11,500
WHCC | JWH
Investment in unconsolidated affiliate
Membership percentage		50.00%
WHCC | JWH
Investment in unconsolidated affiliate
Cash capital contribution		$ 10,200
Joint Venture Partner | JWH
Investment in unconsolidated affiliate
Membership percentage		50.00%
Joint Venture Partner | JWH
Investment in unconsolidated affiliate
Cash capital contribution		$ 10,200
JWH
Investment in unconsolidated affiliate
Number of leased acres for construction and operation of marine terminal facility		55

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Oil and Gas Properties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Restricted cash
Restricted cash	$ 0	$ 0
Oil and gas properties
Capital costs excluded from depletion	$ 98.1

Summary of Significant Accoun_5

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
Extractive Industries
Balance, beginning of period	$ 7,064	$ 15,198
Additions to capitalized exploratory well costs pending the determination of proved reserves		60,847
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	$ (7,064)	(68,981)
Balance, end of period		$ 7,064

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Millions	Jan. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Significant accounting policies
Capitalized interest		$ 5.9	$ 3.1	$ 0.1
Provision for uncollectible accounts		0.2	0.1
Internal Revenue Service ("IRS")
Significant accounting policies
Estimated minimum tax paid	$ 2.3
Unproved Oil and Gas Properties
Significant accounting policies
Impairment of oil and natural gas properties		$ 10.5	$ 20.8	$ 3.1

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 02, 2018	Jan. 01, 2018	Dec. 31, 2017
ASSETS
Oil and gas properties	$ 3,457,897	$ 2,995,687		$ 2,999,728
Accumulated depreciation, depletion and amortization	(518,054)	(367,874)		(368,245)
Other non-current assets	17,250	3,978
Liabilities:
Deferred tax liabilities	112,731	71,537		71,470
Stockholders' equity:
Accumulated earnings	136,773	$ 26,016		$ 25,773
Contract with customers assets and liabilities
Contract assets	0
Performance obligation
Unsatisfied performance obligations	0
Adjustments for ASC 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	(5,960)		$ (4,041)
Accumulated depreciation, depletion and amortization	981		371
Other non-current assets	5,811		3,978
Liabilities:
Deferred tax liabilities	180		67
Stockholders' equity:
Accumulated earnings	(1,012)		$ 243
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	3,463,857
Accumulated depreciation, depletion and amortization	(519,035)
Other non-current assets	11,439
Liabilities:
Deferred tax liabilities	112,551
Stockholders' equity:
Accumulated earnings	$ 137,785

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Consolidated Income Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues
Other income	$ 2,052	$ 1,431	$ 2,131
Operating expenses:
Lease operating expenses	61,620	39,770	12,320
Gathering, processing and transportation	9,856	11,897	6,581
Depreciation, depletion and amortization	296,685	168,250	81,757
Other operating expense	1,064	73	99
Income before income taxes	186,704	11,056	(52,651)
Income tax expense	(40,196)	38,824	5,575
Net income	146,508	49,880	(10,397)
Oil sales
Revenues
Revenues	843,244	342,868	75,938
Natural gas sales
Revenues
Revenues	60,129	59,924	43,487
Natural gas liquid sales
Revenues
Revenues	41,961	$ 22,964	$ 5,786
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Revenues
Other income	1,861
Operating expenses:
Lease operating expenses	63,043
Gathering, processing and transportation	22,703
Depreciation, depletion and amortization	297,295
Other operating expense	459
Income before income taxes	186,180
Income tax expense	(40,083)
Net income	146,097
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Oil sales
Revenues
Revenues	843,329
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Natural gas sales
Revenues
Revenues	64,896
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Natural gas liquid sales
Revenues
Revenues	51,052
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Revenues
Other income	191
Operating expenses:
Lease operating expenses	(1,423)
Gathering, processing and transportation	(12,847)
Depreciation, depletion and amortization	(610)
Other operating expense	605
Income before income taxes	524
Income tax expense	(113)
Net income	411
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Oil sales
Revenues
Revenues	(85)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas sales
Revenues
Revenues	(4,767)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas liquid sales
Revenues
Revenues	$ (9,091)

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 264,853	$ 11,523	$ (14,094)	$ (115,774)	$ 14,066	$ (10,804)	$ 26,366	$ 20,252	$ 146,508	$ 49,880	$ (47,076)
Depreciation, depletion and amortization									296,685	168,250	81,757
Deferred income tax expense									41,193	(39,831)	(5,575)
Consideration paid to customers, net of amortization									(1,817)
Cash flows from investing activities:
Additions to oil and gas properties									(1,051,891)	$ (700,546)	$ (125,837)
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Cash flows from operating activities:
Net income (loss)									146,097
Depreciation, depletion and amortization									297,295
Deferred income tax expense									41,080
Cash flows from investing activities:
Additions to oil and gas properties									(1,053,811)
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Cash flows from operating activities:
Net income (loss)									411
Depreciation, depletion and amortization									(610)
Deferred income tax expense									113
Consideration paid to customers, net of amortization									(1,817)
Cash flows from investing activities:
Additions to oil and gas properties									$ 1,920

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 48,717	$ 12,246	$ 7,152
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities	(82,358)	134,589	(4,492)
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions	$ (1,247)	$ (847)	$ (5,175)

Summary of Significant Accou_11

Summary of Significant Accounting Policies - Leases (Details) - Accounting Standards Update 2016-02 - Proforma Adjustment $ in Millions	Dec. 31, 2018USD ($)
Minimum
New accounting pronouncements - Leases
Operating Lease, Right-of-Use Asset	$ 35
Maximum
New accounting pronouncements - Leases
Operating Lease, Right-of-Use Asset	$ 65

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Acquisition-related costs	$ 1,117	$ 4,348	$ 553

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Additional Information (Details) $ in Thousands

Mar. 29, 2018USD ($)

Jan. 04, 2018USD ($)a

Jun. 30, 2017USD ($)shares

Dec. 19, 2016USD ($)ashares

Nov. 08, 2016USD ($)aitem

Oct. 31, 2018USD ($)

Jun. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Mar. 31, 2017USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Sep. 30, 2018USD ($)

Business Acquisitions

Acquisitions of oil and gas properties

$ 53,814

$ 551,242

$ 436,072

Payments to acquire other property, plant and equipment

83,597

15,959

5,403

Capitalized assets

107,279

53,003

Divestitures

Impairment of NLA Disposal Group

$ 214,300

214,274

Pre-tax loss of NLA Disposal Group

202,700

5,900

NLA Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations

Divestitures

Proceeds from divestiture before final purchase price adjustments

$ 206,400

Final purchase price adjustments

$ 4,800

4,800

Final proceeds from divestiture

211,200

Divestiture related costs

3,800

Contingent consideration arrangement divestiture

$ 35,000

$ 35,000

Period of time over which contingent payments will be determined

3 years

Payments received on contingent consideration arrangements

$ 400

Gain on sale of NLA Disposal Group

2,800

Fee revenue from transitional accounting and land service provided

$ 900

Sand Mine

Business Acquisitions

Capitalized sand assets

66,100

Eagle Ford Acquisitions

Business Acquisitions

Acquisitions of oil and gas properties

53,800

Capitalized transaction costs

1,500

Purchase price allocated to unproved oil and natural gas properties

$ 48,000

APC/KKR Acquisitions

Business Acquisitions

Payments to acquire oil and natural gas properties

$ 533,002

Business acquisition, value of shares issued

$ 60,754

Business acquisition, date of acquisition agreement

May 10, 2017

Business acquisition, date of completion

Jun. 30, 2017

Revenues related to properties obtained in the Acquisition

42,600

Income/loss related to properties obtained in the Acquisition

11,100

APC Subs

Business Acquisitions

Payments to acquire oil and natural gas properties

$ 533,600

KKR

Business Acquisitions

Business acquisition, value of shares issued

$ 60,800

Business acquisition, shares issued | shares

5,518,125

Third Parties Acquisition | Burleson County, TX

Business Acquisitions

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 Acquisitions

Payments to acquire oil and natural gas properties

$ 389,800

Purchase price allocated to unproved oil and natural gas properties

$ 162,900

Business acquisition, post-closing receipt

$ 3,900

Revenues related to properties obtained in the Acquisition

2,000

Income/loss related to properties obtained in the Acquisition

$ 400

Area of oil and natural gas properties acquired | a

158,000

Rosewood Acquisition

Business Acquisitions

Purchase price allocated to unproved oil and natural gas properties

$ 18,300

Area Of Land | a

7,500

Business acquisition, shares issued | shares

1,308,427

Burleson Sand | Sand Mine

Business Acquisitions

Surface and sand rights acquired | a

727

Payments to acquire other property, plant and equipment

$ 9,000

Esquisto II | November Acquisition

Business Acquisitions

Payments to acquire oil and natural gas properties

$ 30,000

Purchase price allocated to unproved oil and natural gas properties

$ 29,400

Area Of Land | a

4,900

Number of oil and gas producing wells | item

9

Acquisitions and Divestitures_3

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
APC/KKR Acquisitions
Business Acquisitions
Cash paid	$ 533,002
Common stock, Purchase price	60,754
Total consideration, Purchase price	593,756
Final Purchase Price Allocation
Proved oil and gas properties, Purchase price	264,467
Unproved oil and gas properties, Purchase price	333,778
Accounts receivable, Purchase Price	60
Asset retirement obligations, Purchase Price	(2,500)
Accrued liabilities, Purchase Price	(2,049)
Total identifiable net assets, Purchase Price	$ 593,756
Burleson North Acquisition
Business Acquisitions
Cash paid		$ 389,800
Burleson North Acquisition | Final Purchase Price Allocation
Business Acquisitions
Oil and natural gas properties, Purchase Price		395,591
Other property and equipment, Purchase Price		478
Final Purchase Price Allocation
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 Acquisitions
Oil and natural gas properties, Purchase Price		$ 19,626
November Acquisition
Business Acquisitions
Oil and natural gas properties, Purchase Price			$ 29,973

Acquisitions and Divestitures_4

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
APC/KKR Acquisitions
Business Acquisitions
Revenues	$ 475,396	$ 226,502
Net loss	$ 71,287	$ (11,290)
Earnings per share (basic and diluted)	$ 0.51	$ (0.10)
Burleson North Acquisition
Business Acquisitions
Revenues		$ 176,082
Net loss		$ (34,894)

Fair Value Measurements of Fi_3

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring - Commodity Contract - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets:
Fair value of derivative asset	$ 72,710	$ 2,422
Liabilities:
Fair value of derivative liability	508	76,750
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	72,710	2,422
Liabilities:
Fair value of derivative liability	$ 508	$ 76,750

Fair Value Measurements of Fi_4

Fair Value Measurements of Financial Instruments - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Proved Oil and Gas Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 0	$ 0	$ 0
Unproved Oil and Gas Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 10,500	$ 20,800	$ 3,100

Risk Management and Derivativ_3

Risk Management and Derivative Instruments - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure
Derivative instruments designated as cash flow hedges	$ 0
Deferred premiums	9.3	$ 6.3
Derivative assets	72.2
Derivative liability, right to offset amount	72.2
Cash collateral received or pledged	$ 0

Risk Management and Derivativ_4

Risk Management and Derivative Instruments - Schedule of Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2018MMBTU$ / bblbbl
Crude Oil Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (Bbls) | bbl	6,652,369
Weighted-average fixed price	54.45
Crude Oil Derivative Contracts Put Options 2019
Derivative [Line Items]
Volume (Bbls) | bbl	1,749,757
Weighted-average floor price	53.83
Weighted-average put premium	(5.43)
Crude Oil Derivative Contracts Fixed Price Swap 2020
Derivative [Line Items]
Volume (Bbls) | bbl	4,511,681
Weighted-average fixed price	53.49
Natural Gas Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (MMBtu) | MMBTU	6,425,146
Weighted-average fixed price	2.79
Natural Gas Derivative Contracts Fixed Price Swap 2020
Derivative [Line Items]
Volume (MMBtu) | MMBTU	4,846,020
Weighted-average fixed price	2.76

Risk Management and Derivativ_5

Risk Management and Derivative 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, 2018	Dec. 31, 2017
Derivative [Line Items]
Asset Derivatives, Net recorded fair value	$ 72,200
Short-term Derivative Instruments | Commodity Contract
Derivative [Line Items]
Asset Derivatives, Gross fair value	54,131	$ 2,336
Asset Derivatives, Net recorded fair value	54,131	2,336
Liability Derivatives, Gross fair value	508	58,074
Liability Derivatives, Net recorded fair value	508	58,074
Long-term Derivative Instruments | Commodity Contract
Derivative [Line Items]
Asset Derivatives, Gross fair value	18,579	86
Asset Derivatives, Net recorded fair value	18,579	86
Liability Derivatives, Gross fair value	0	18,676
Liability Derivatives, Net recorded fair value	$ 0	$ 18,676

Risk Management and Derivativ_6

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ 35,393	$ (55,483)	$ (26,771)

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 70,900	$ 67,584
Joint interest billings	17,491	9,467
Severance tax	1,352	171
Derivative receivable	308
North Louisiana Settlement receivable		5,955
Environmental remediation	1,511
Other current receivables	196	1,026
Allowance for doubtful accounts	(200)	(100)	$ (100)	$ (50)
Total	$ 91,558	$ 84,103

Accounts Receivable - Schedul_2

Accounts Receivable - Schedule of Accounts Notes Loans and Financing Receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2016
Accounts Notes Loans And Financing Receivable Gross Allowance And Net [Abstract]
Balance at beginning of period	$ 100	$ 50
Charged to costs and expenses	100	50
Balance at end of period	$ 200	$ 100

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Payables And Accruals [Abstract]
Capital expenditures	$ 80,897	$ 162,260
Preferred stock cash dividends	4,479
Deferred rent		410
Lease operating expense	6,604	5,796
General and administrative	4,335	1,642
Severance and ad valorem taxes	5,283	3,463
Interest expense	20,122	17,177
Derivative payable	1,746	5,281
Income taxes		991
Other accrued liabilities	1,167	2,932
Total	$ 124,633	$ 199,952

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 14,557	$ 11,033
Accretion expense	573	713
Liabilities incurred	743	3,137
Revisions	70	(326)
Disposition of wells and gathering system	(7,627)
Asset retirement obligations at end of period	8,316	14,557
Less: current portion	90	90
Asset retirement obligations - long-term	$ 8,226	$ 14,467

Long Term Debt - Schedule of De

Long Term Debt - Schedule of Debt Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument
Unamortized debt issuance costs	$ (17,257)	$ (15,619)
Total long-term debt	1,191,376	770,596
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument
Long-term debt, gross	700,000	500,000
Unamortized discounts	(782)	(4,914)
Unamortized debt issuance costs	(11,842)	(10,843)
WRD Revolving Credit Facility
Debt Instrument
Long-term debt, gross	$ 504,000	$ 286,353

Long Term Debt - Schedule of _2

Long Term Debt - Schedule of Debt Obligations Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
6.875% Senior Unsecured Notes, Due February 2025 | Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Debt Instrument
Estimated fair value of fixed rate debt	$ 661.5	$ 511.3

Long Term Debt - Schedule of Bo

Long Term Debt - Schedule of Borrowing Base Revolving Credit Facility (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Oct. 15, 2018	Mar. 23, 2018	Mar. 22, 2018	Oct. 04, 2017	Oct. 03, 2017	Jun. 30, 2017	Jun. 29, 2017	Feb. 01, 2017	Dec. 19, 2016
Line Of Credit Facility
WRD revolving credit facility							$ 650,000	$ 450,000
WRD Revolving Credit Facility
Line Of Credit Facility
WRD revolving credit facility	$ 1,300,000	$ 1,300,000	$ 1,050,000	$ 875,000	$ 875,000	$ 612,500			$ 362,500	$ 450,000

Long Term Debt - Amendment to t

Long Term Debt - Amendment to the Credit Agreement (Details) - WRD Revolving Credit Facility	Oct. 15, 2018	Dec. 31, 2018
LIBOR
Debt Instrument
Variable margin rate		1.00%
Greater than or equal to 90%
Debt Instrument
Commitment fee	0.50%
Greater than or equal to 90% | LIBOR
Debt Instrument
Variable margin rate	2.50%
Greater than or equal to 90% | Base Rate
Debt Instrument
Variable margin rate	1.50%
Greater than or equal to 75% but less than 90%
Debt Instrument
Commitment fee	0.50%
Greater than or equal to 75% but less than 90% | LIBOR
Debt Instrument
Variable margin rate	2.25%
Greater than or equal to 75% but less than 90% | Base Rate
Debt Instrument
Variable margin rate	1.25%
Greater than or equal to 50% but less than 75%
Debt Instrument
Commitment fee	0.50%
Greater than or equal to 50% but less than 75% | LIBOR
Debt Instrument
Variable margin rate	2.00%
Greater than or equal to 50% but less than 75% | Base Rate
Debt Instrument
Variable margin rate	1.00%
Greater than or equal to 25% but less than 50%
Debt Instrument
Commitment fee	0.375%
Greater than or equal to 25% but less than 50% | LIBOR
Debt Instrument
Variable margin rate	1.75%
Greater than or equal to 25% but less than 50% | Base Rate
Debt Instrument
Variable margin rate	0.75%
Less than 25%
Debt Instrument
Commitment fee	0.375%
Less than 25% | LIBOR
Debt Instrument
Variable margin rate	1.50%
Less than 25% | Base Rate
Debt Instrument
Variable margin rate	0.50%

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Details) $ in Thousands

Oct. 15, 2018USD ($)

Apr. 20, 2018USD ($)

Sep. 19, 2017USD ($)

Feb. 01, 2017USD ($)

Dec. 19, 2016USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Mar. 23, 2018USD ($)

Mar. 22, 2018USD ($)

Nov. 20, 2017

Oct. 04, 2017USD ($)

Oct. 03, 2017USD ($)

Jun. 30, 2017USD ($)

Jun. 29, 2017USD ($)

Debt Instrument

WRD revolving credit facility

$ 650,000

$ 450,000

Restricted Payment

$ 75,000

$ 50,000

Proceeds from senior notes offering

$ 204,000

$ 494,744

6.875% Senior Unsecured Notes, Due February 2025

Debt Instrument

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

Aggregate principal amount

$ 200,000

$ 150,000

$ 350,000

Debt instrument interest rate percentage

6.875%

Issue price of notes as a percentage of par value

102.00%

98.26%

99.244%

Proceeds from senior notes offering

$ 201,000

$ 144,700

$ 338,600

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

Debt instrument redemption percentage of principal amount

35.00%

WRD Revolving Credit Facility

Debt Instrument

Line of credit expiration period

5 years

Aggregate maximum credit amount

$ 1,000,000

$ 2,000,000

$ 1,000,000

WRD revolving credit facility

$ 1,300,000

$ 362,500

$ 450,000

$ 1,300,000

$ 1,050,000

$ 875,000

$ 875,000

$ 612,500

Decrease in pricing grid

0.25%

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 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 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 per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies per annum according to the total commitment usage.

WRD Revolving Credit Facility | Federal Funds Effective Swap Rate

Debt Instrument

Interest rate spread

0.50%

WRD Revolving Credit Facility | LIBOR

Debt Instrument

Interest rate spread

1.00%

WRD Revolving Credit Facility | Minimum

Debt Instrument

Secured Credit Facility lien percentage

85.00%

Ratio of current assets to current liabilities

1

WRD Revolving Credit Facility | Maximum

Debt Instrument

Ratio of total debt to EBITDAX

4

WRD Revolving Credit Facility | Certain Properties Prior to February 2, 2017

Debt Instrument

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, 2018	Dec. 31, 2017	Dec. 31, 2016
WRD Revolving Credit Facility
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates	4.06%	3.60%	3.52%
WHR II Revolving Credit Facility Terminated December 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			3.03%
Esquisto - Revolving Credit Facility Terminated December 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			2.84%
Esquisto - Revolving Credit Facility Terminated January 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			2.97%
Esquisto - Second Lien Terminated In January 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			9.50%

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, 2018	Dec. 31, 2017
Debt Instrument
Long-term	$ 3,592	$ 3,573
Unamortized deferred financing costs	17,257	15,619
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument
Unamortized deferred financing costs	11,842	10,843
WRD Revolving Credit Facility
Debt Instrument
Current	1,823	1,203
Long-term	$ 3,592	$ 3,573

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, 2018director$ / shares	Dec. 31, 2017USD ($)
Temporary Equity
Proceeds from the issuance of preferred stock						$ 435,000
June 30, 2018 Anniversary
Temporary Equity
Conversion of stock, conversion price | $ / shares					$ 13.90
Redeemable Convertible Preferred Stock
Temporary Equity
Quarterly dividend, amount	$ 6,656	$ 6,558
Dividend, record date	Jan. 15, 2018	Oct. 15, 2017
Dividend, date paid	Jan. 31, 2018	Oct. 31, 2017
Beneficial conversion feature	$ 1,900
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity
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
Preferred Stock Purchase Agreement | 10% Ownership of Outstanding Common Stock
Temporary Equity
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
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
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
Holding percentage of outstanding common stock to elect director					5.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock
Temporary Equity
Proceeds from the issuance of preferred stock				$ 435,000
Preferred stock, shares issued | shares				435,000
Preferred equity, initial accreted value, per share | $ / shares	$ 1,024			$ 1,000
Preferred stock, dividend rate percentage					6.00%
Preferred stock redemption date					Jun. 30, 2022
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | December 30, 2019 Anniversary
Temporary Equity
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 | June 30, 2021 Anniversary
Temporary Equity
Percentage of preferred stock conversion price					140.00%
Number of trading days required for conversion					25 days
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2023 Anniversary
Temporary Equity
Multiple percentage on preferred stock accreted value					112.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2024 Anniversary
Temporary Equity
Multiple percentage on preferred stock accreted value					109.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | After June 30, 2024 Anniversary
Temporary Equity
Multiple percentage on preferred stock accreted value					106.00%

Preferred Stock - Schedule of P

Preferred Stock - Schedule of Preferred Stock (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Changes in common shares
Paid-in-kind dividend	$ 2,243	$ 13,146
Beneficial conversion feature of preferred stock	(1,872)
Amortized beneficial conversion feature	1,872
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock
Changes in common shares
Beginning Balance	445,483	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
Paid-in-kind dividend	2,243
Beneficial conversion feature of preferred stock	(1,872)
Amortized beneficial conversion feature	1,872
Ending Balance	$ 447,726	$ 445,483

Preferred Stock - Quarterly cas

Preferred Stock - Quarterly cash dividends (Details) - USD ($)	Jan. 31, 2019	Jan. 31, 2018	Oct. 31, 2017	Jul. 31, 2017	Oct. 31, 2018	Jul. 31, 2018	Apr. 30, 2018	Dec. 31, 2018
Temporary Equity
Amortized beneficial conversion feature								$ 1,872,000
Preferred stock dividend paid								$ 20,267,000
Redeemable Convertible Preferred Stock
Temporary Equity
Quarterly dividend, amount		$ 6,656,000	$ 6,558,000
Beneficial conversion feature		$ 1,900,000
Dividend, date paid		Jan. 31, 2018	Oct. 31, 2017
Dividend, record date		Jan. 15, 2018	Oct. 15, 2017
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity
Quarterly dividend announced date				Jul. 31, 2017
Quarterly dividend, amount				$ 2,175,000
Dividend, record date				Jul. 15, 2017
Redeemable Convertible Preferred Stock | Cash Dividend
Temporary Equity
Preferred stock dividend paid					$ 6.756	$ 6.756	$ 6.756
Dividend, date paid					Oct. 31, 2018	Jul. 31, 2018	Apr. 30, 2018
Dividend, record date					Oct. 15, 2018	Jul. 15, 2018	Apr. 15, 2018
Redeemable Convertible Preferred Stock | Cash Dividend | Subsequent Event
Temporary Equity
Preferred stock dividend paid	$ 6.831
Dividend, date paid	Jan. 31, 2019
Dividend, record date	Jan. 15, 2019

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Jun. 30, 2017	Jan. 17, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018
Changes in common shares
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
Previous Owner
Changes in common shares
Capital contributions				97,000
Predecessor
Changes in common shares
Capital contributions				$ 10,837
Promissory note advances to fund future capital commitments and carried an interest rate				2.50%
KKR
Changes in common shares
Business acquisition, shares issued	5,518,125
Business acquisition, value of shares issued	$ 60,800
Common Stock
Changes in common shares
Issued and sold of initial public offering		2,297,100	7,815,225

Equity - Summary of Changes in

Equity - Summary of Changes in Common Shares Issued (Details) - USD ($) $ in Thousands	Jan. 17, 2017	Dec. 19, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in common shares
Common stock issued					27,500,000
Payments for employee withholding taxes			$ 6,894	$ 564
Rosewood Acquisition
Changes in common shares
Shares of common stock issued with corporate reorganization and acquisition		1,308,427
Common Stock
Changes in common shares
Balance, Beginning of Period			101,137,277	91,680,441
Common stock issued	2,297,100			7,815,225
Restricted common stock issued			1,076,165	1,676,284
Restricted common stock forfeited			(63,768)	(717)
Repurchase of vested restricted shares			(355,819)	(33,956)
Balance, End of Period			101,793,855	101,137,277	91,680,441

Equity - Summary of Advances an

Equity - Summary of Advances and Payments of Promissory Note Advances (Details) - Predecessor	12 Months Ended
	Dec. 31, 2016USD ($)
Changes in common shares
Beginning balance	$ 2,443
Advances	101
Payments	(20)
Accrued Interest	51
Dissolution	(2,575)
Principal
Changes in common shares
Beginning balance	2,367
Advances	101
Payments	(20)
Dissolution	(2,448)
Interest
Changes in common shares
Beginning balance	76
Advances	0
Accrued Interest	51
Dissolution	$ (127)

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Numerator:
Net income (loss) available to WRD									$ 146,508	$ 49,880	$ (10,397)
Less: Preferred stock dividends	$ 6,756	$ 6,756	$ 7,961	$ 7,389	$ 6,623	$ 6,450	$ 73	$ 0	28,862	13,146
Less: Undistributed earnings allocated to participating securities									30,344	5,612
Net income (loss) available to common stockholders	$ 228,986	$ 3,534	$ (22,055)	$ (123,163)	$ 2,218	$ (17,254)	$ 25,906	$ 20,252	$ 87,302	$ 31,122	$ (10,397)
Denominator:
Weighted-average common shares outstanding									99,498	96,324	91,327
Basic	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)
Diluted	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)

Earnings Per Share - Schedule_2

Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS Additional Information (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share
Shares excluded in calculation of diluted EPS	32,363	16,008
Restricted Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share
Shares excluded in calculation of diluted EPS	775	628

Long Term Incentive Plans - Add

Long Term Incentive Plans - Additional Information (Details) - 2016 Long-Term Incentive Plan - Restricted Stock - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award
Aggregate grant date fair value	$ 27.5	$ 23.3
Grant date market price	$ 25.57	$ 13.88	$ 14.50
Common stock authorized for issuance under plan	9,512,500
Recognized compensation expense	$ 19.5	$ 6.6
Unrecognized compensation cost	$ 28.7
Unrecognized compensation cost, weighted-average period	2 years
Minimum
Share Based Compensation Arrangement By Share Based Payment Award
Grant date market price	$ 18.14	$ 10.91
Vesting period	1 year
Maximum
Share Based Compensation Arrangement By Share Based Payment Award
Grant date market price	$ 27.07	$ 14.22
Vesting period	3 years
Recognized compensation expense			$ 0.1

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Restricted common shares outstanding, Beginning Balance	1,897,790	353,334
Restricted commons shares, Granted	1,076,165	1,676,284	353,334
Restricted commons shares, Forfeited	(63,768)	(717)
Restricted commons shares, Vested	(1,069,933)	(131,111)
Restricted common shares outstanding, Ending Balance	1,840,254	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	$ 13.95	$ 14.50
Restricted common shares, Granted, Weighted-Average Grant Date Fair Value per Share	25.57	13.88	$ 14.50
Restricted common shares, Forfeited, Weighted-Average Grant Date Fair Value per Share	16.45	13.94
Restricted common shares, Vested, Weighted-Average Grant Date Fair Value per Share	15.66	14.50
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Ending Balance	$ 19.66	$ 13.95	$ 14.50

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) - USD ($) $ in Thousands	May 14, 2018	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award
Incentive unit compensation expense		$ 13,776
Contribution related to incentive unit compensation expense		$ 13,776
Esquisto Holdings | Incentive Award Units
Share Based Compensation Arrangement By Share Based Payment Award
Stock distribution	500,932

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) $ in Millions	Jan. 17, 2017shares	Dec. 31, 2018USD ($)director	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Jun. 30, 2017shares
Related Party Transactions
Issued and sold of initial public offering | shares				27,500,000
Initial offering lock-up period		180 days
Anticipated aggregate common stock offering price		$ 75
Common Stock
Related Party Transactions
Issued and sold of initial public offering | shares	2,297,100		7,815,225
Carlyle Group, L.P.
Related Party Transactions
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds		55.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Minimum
Related Party Transactions
Common stock ownership percentage		15.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement One | Minimum
Related Party Transactions
Common stock ownership percentage		50.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Two | Minimum
Related Party Transactions
Common stock ownership percentage		35.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Two | Maximum
Related Party Transactions
Common stock ownership percentage		50.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Three | Minimum
Related Party Transactions
Common stock ownership percentage		15.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Three | Maximum
Related Party Transactions
Common stock ownership percentage		35.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Four | Minimum
Related Party Transactions
Common stock ownership percentage		5.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Four | Maximum
Related Party Transactions
Common stock ownership percentage		15.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Five | Maximum
Related Party Transactions
Common stock ownership percentage		5.00%
Genesis Energy Partners, L.P
Related Party Transactions
Proceeds from sale of hydrocarbons and other liquids		$ 1.2	$ 2.2
Cretic Energy Services, LLC | Drilling and Completion Activities
Related Party Transactions
Payments made to related party		0	0.2
Affiliate of Carlyle Group
Related Party Transactions
Preferred stock, shares issued | shares					435,000
CH4 Energy
Related Party Transactions
Payments made to related party		0.2	0.5
CH4 Energy | Corporate Reorganization
Related Party Transactions
Leasehold Interests		0.1
CH4 Energy | Office Rental and Parking
Related Party Transactions
Payments made to related party			0.2
CH4 Energy | Landman Services and Expenses Incurred in 2016
Related Party Transactions
Payments made to related party				$ 0.3
Archrock Inc.
Related Party Transactions
Payments made to related party		$ 0.1
NGP ECM | Director and Advisory Fees and Reimbursement of IPO Costs | Maximum
Related Party Transactions
Related party payments (receipts), net			$ 0.2
NGP ECM | NGP X US Holdings
Related Party Transactions
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds		40.00%
NGP ECM | NGP XI
Related Party Transactions
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 Transactions
Issued and sold of initial public offering | shares				21,200,084
Esquisto Holdings | Corporate Reorganization | Common Stock
Related Party Transactions
Issued and sold of initial public offering | shares				38,755,330
Acquisitions Co. | Corporate Reorganization | Common Stock
Related Party Transactions
Issued and sold of initial public offering | shares				2,563,266
Wild Horse Holdings And Esquisto Holdings
Related Party Transactions
Number of Board of Directors nominees each | director		1
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement One
Related Party Transactions
Number of Board of Directors nominees each | director		3
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Two
Related Party Transactions
Number of Board of Directors nominees each | director		2
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Three
Related Party Transactions
Number of Board of Directors nominees each | director		1
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Four
Related Party Transactions
Number of Board of Directors nominees each | director		1

Segment Disclosures - Additiona

Segment Disclosures - Additional Information (Details) - segment	Mar. 29, 2018	Dec. 31, 2018
Segment Reporting [Abstract]
Number of operating segments	2	1
Number of reportable segments	1	1

Segment Disclosures - Major Cus

Segment Disclosures - Major Customers (Details) - Customer Concentration Risk - Sales Revenue, Segment	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Energy Transfer Equity LP. and Subsidiaries
Concentration risk percentage	49.00%	56.00%	63.00%
Koch Industries, Inc.
Concentration risk percentage	19.00%	4.00%
Royal Dutch Shell Plc and Subsidiaries
Concentration risk percentage	18.00%	21.00%	12.00%
Cima Energy Ltd.
Concentration risk percentage			15.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Federal statutory tax rate	21.00%	35.00%	35.00%
Liability for unrecognized tax benefits	$ 0
Disallowed business interest deduction carryforward	47,600
Valuation allowance	1,820
Domestic Tax Authority [Member]
Income Tax Contingency [Line Items]
Income tax operating loss carry forward	218,000
Portion of income tax operating loss carry forward with no expiration	$ 65,900
Domestic Tax Authority [Member] | Earliest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2036
Domestic Tax Authority [Member] | Latest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2037
State and Local Jurisdiction [Member]
Income Tax Contingency [Line Items]
Income tax operating loss carry forward	$ 28,800
Valuation allowance	$ 1,800
State and Local Jurisdiction [Member] | Earliest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2036
State and Local Jurisdiction [Member] | Latest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2038

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current income taxes:
Federal	$ (997)	$ 997
State		10
Total current income tax expense (benefit)	(997)	1,007
Deferred income taxes:
Federal	43,143	(40,529)	$ (5,737)
State	(1,950)	698	162
Total deferred income tax expense (benefit)	41,193	(39,831)	(5,575)
Total income tax expense (benefit)	$ 40,196	$ (38,824)	$ (5,575)

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Income tax expense benefit continuing operations income tax reconciliation
Expected tax expense (benefit) at federal statutory rate		$ 39,208	$ 3,870	$ (18,428)
State income tax expense (benefit), net of federal benefit		(3,360)	460	105
Pass-through entities				12,499
Incentive unit compensation		2,893
Stock-based compensation		(1,070)
Valuation allowance		1,820		234
Change in tax rate	$ (43,400)		(43,431)
Change in prior period estimates		24	315
Other		681	(38)	15
Total income tax expense (benefit)		$ 40,196	$ (38,824)	$ (5,575)
Federal statutory tax rate		21.00%	35.00%	35.00%

Income Taxes - Components of Ne

Income Taxes - Components of Net Deferred Income Tax Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred income tax assets:
Net operating loss carryforwards	$ 47,609	$ 29,866
Disallowed business interest deduction carryforward	9,992
Minimum tax credit carryforward		997
Asset retirement obligation	1,796	3,311
Derivatives		16,903
Other	3,860	2,153
Total deferred income tax assets	63,257	53,230
Valuation allowance	(1,820)
Net deferred income tax assets	61,437	53,230
Deferred income tax liabilities:
Property, plant and equipment	158,868	124,700
Derivatives	15,300
Total deferred income tax liabilities	174,168	124,700
Net deferred income tax liabilities	$ 112,731	$ 71,470

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Thousands	Aug. 02, 2018director	Jun. 01, 2017USD ($)item	Mar. 15, 2017USD ($)item	Dec. 31, 2018USD ($)leaseacre ft	Dec. 31, 2017USD ($)agreement	Dec. 31, 2016USD ($)
Commitments and contingencies
North Louisiana Settlement					$ (7,000)
Income tax benefit (expense)				$ (40,196)	38,824	$ 5,575
North Louisiana Settlement receivable					$ 5,955
Dedicated Fracturing Fleet Services Agreements
Commitments and contingencies
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	$ 2,700
Minimum number of stages to be completed for milestone payments | item		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	$ 1,400
Interruptible Water Availability Agreement
Commitments and contingencies
Interruptible water availability agreement, start date				Feb. 1, 2017
Interruptible water availability agreement, end date				Dec. 31, 2021
Aggregate of acre-feet of water per year | acre ft				6,978
Agreement payment				$ 500	$ 400
Office Leases
Commitments and contingencies
Rent expense				$ 800	1,000	900
Period after which lease can be terminated penalty-free				2 years
Number of leases executed | lease				2
Compressors
Commitments and contingencies
Rent expense				$ 5,400	2,000	$ 600
Maximum | Drilling Services Agreements
Commitments and contingencies
Term of agreement for completion of wells and drilling operations				1 year
Maximum | Compressors
Commitments and contingencies
Lease term				13 months
Klein v. Graham, et al
Commitments and contingencies
Number of directors named in legal action | director	7
Number of former directors named in a legal action | director	1
North Louisiana Settlement
Commitments and contingencies
North Louisiana Settlement					7,000
Income tax benefit (expense)					$ 1,600
Settlement receivable collected				$ 5,900

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Future Minimum Lease Obligation (Detail) $ in Thousands	Dec. 31, 2018USD ($)
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	$ 32,597
Operating Leases, Future Minimum Payments, Due 2020	9,862
Operating Leases, Future Minimum Payments, Due 2021	6,257
Operating Leases, Future Minimum Payments, Due 2022	4,940
Operating Leases, Future Minimum Payments, Due 2023	3,153
Office Lease
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	2,399
Operating Leases, Future Minimum Payments, Due 2020	2,435
Operating Leases, Future Minimum Payments, Due 2021	2,398
Operating Leases, Future Minimum Payments, Due 2022	2,216
Operating Leases, Future Minimum Payments, Due 2023	2,251
Dedicated Fracturing Fleet Services Agreements
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	21,000
Sand Mine Equipment
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	5,055
Operating Leases, Future Minimum Payments, Due 2020	3,436
Compressors
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	4,143
Operating Leases, Future Minimum Payments, Due 2020	3,991
Operating Leases, Future Minimum Payments, Due 2021	3,859
Operating Leases, Future Minimum Payments, Due 2022	2,724
Operating Leases, Future Minimum Payments, Due 2023	$ 902

Quarterly Financial accounting

Quarterly Financial accounting (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 243,726	$ 259,490	$ 225,413	$ 218,757	$ 180,236	$ 122,486	$ 70,173	$ 54,292	$ 947,386	$ 427,187	$ 127,342
Operating income (loss)	88,196	122,776	101,370	(100,053)	64,582	32,599	2,078	6,206	212,289	105,465	(16,228)
Net income (loss)	264,853	11,523	(14,094)	(115,774)	14,066	(10,804)	26,366	20,252	146,508	49,880	(47,076)
Preferred stock dividends	6,756	6,756	7,961	7,389	6,623	6,450	73	0	28,862	13,146
Net income (loss) available to common stockholders	$ 228,986	$ 3,534	$ (22,055)	$ (123,163)	$ 2,218	$ (17,254)	$ 25,906	$ 20,252	$ 87,302	$ 31,122	$ (10,397)
Basic earnings (loss) per share	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)
Diluted earnings (loss) per share	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)
Deferred tax benefit - change in tax rate					$ 43,400					$ 43,431

Supplemental Oil and Gas Info_3

Supplemental Oil and Gas Information - Proved Reserves, Prices (Detail)	12 Months Ended
	Dec. 31, 2018$ / MMBTU$ / bbl	Dec. 31, 2017$ / MMBTU$ / bbl	Dec. 31, 2016$ / MMBTU$ / bbl
Oil
Price of oil and gas	65.56	51.34	42.75
Natural gas liquid sales
Price of oil and gas	65.56	51.34	42.75
Natural Gas
Price of oil and gas | $ / MMBTU	3.10	2.98	2.48

Supplemental Oil and Gas Info_4

Supplemental Oil and Gas Information - Estimates of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoeMMcfMBbls
Reserve Quantities
Beginning of the year | MBoe	454,315	152,505	103,040
Extensions, discoveries and additions | MBoe	119,211	162,559	26,940
Purchase of minerals in place | MBoe	757	70,593	30,916
Sales of minerals in place | MBoe	(67,180)
Production | MBoe	(18,316)	(11,222)	(5,289)
Revision of previous estimates | MBoe	(82,737)	79,880	(3,102)
End of year | MBoe	406,050	454,315	152,505
Proved developed reserves, Beginning of year | MBoe	114,495	47,270	33,570
Proved developed reserves, End of year | MBoe	95,356	114,495	47,270
Proved undeveloped reserves, Beginning of year | MBoe	339,820	105,235	69,470
Proved undeveloped reserves, End of year | MBoe	310,694	339,820	105,235
Oil
Reserve Quantities
Beginning of the year	282,798	87,447	36,650
Extensions, discoveries and additions	81,174	93,454	18,870
Purchase of minerals in place	520	59,169	26,835
Sales of minerals in place	(1,272)
Production	(12,585)	(6,606)	(1,848)
Revision of previous estimates	(65,369)	49,334	6,940
End of year	285,266	282,798	87,447
Proved developed reserves, Beginning of year	65,023	19,192	7,503
Proved developed reserves, End of year	66,398	65,023	19,192
Proved undeveloped reserves, Beginning of year	217,775	68,255	29,147
Proved undeveloped reserves, End of year	218,868	217,775	68,255
Natural Gas
Reserve Quantities
Beginning of the year | MMcf	683,808	325,102	344,959
Extensions, discoveries and additions | MMcf	129,962	279,368	32,782
Purchase of minerals in place | MMcf	727	28,106	13,545
Sales of minerals in place | MMcf	(393,057)
Production | MMcf	(21,531)	(20,463)	(17,820)
Revision of previous estimates | MMcf	(21,736)	71,695	(48,364)
End of year | MMcf	378,173	683,808	325,102
Proved developed reserves, Beginning of year | MMcf	221,517	145,880	142,990
Proved developed reserves, End of year | MMcf	88,936	221,517	145,880
Proved undeveloped reserves, Beginning of year | MMcf	462,291	179,222	201,969
Proved undeveloped reserves, End of year | MMcf	289,237	462,291	179,222
Natural gas liquid sales
Reserve Quantities
Beginning of the year	57,550	10,874	8,897
Extensions, discoveries and additions	16,377	22,545	2,606
Purchase of minerals in place	116	6,740	1,823
Sales of minerals in place	(398)
Production	(2,143)	(1,206)	(471)
Revision of previous estimates	(13,747)	18,597	(1,981)
End of year	57,755	57,550	10,874
Proved developed reserves, Beginning of year	12,553	3,765	2,235
Proved developed reserves, End of year	14,135	12,553	3,765
Proved undeveloped reserves, Beginning of year	44,997	7,109	6,662
Proved undeveloped reserves, End of year	43,620	44,997	7,109

Supplemental Oil and Gas Info_5

Supplemental Oil and Gas Information - Categorical Information on Estimates of Net Reserves (Detail) - MBoe	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reserve Quantities
Extensions, discoveries and additions	119,211	162,559	26,940
Sales of minerals in place	(67,180)
Production	18,316	11,222	5,289
Purchase of minerals in place	757	70,593	30,916
Revision of previous estimates	(82,737)	79,880	(3,102)
Commodity Price Changes
Reserve Quantities
Revision of previous estimates	4,216	7,461	(711)
Performance Related
Reserve Quantities
Revision of previous estimates	(86,953)	72,419	(2,391)
North Louisiana
Reserve Quantities
Extensions, discoveries and additions		20,313
Sales of minerals in place	(67,180)
Production	18,316
Eagle Ford
Reserve Quantities
Extensions, discoveries and additions		142,246	22,809
RCT field in Louisiana
Reserve Quantities
Extensions, discoveries and additions			4,131
APC/KKR Acquisitions
Reserve Quantities
Purchase of minerals in place		70,593
Burleson North Acquisition
Reserve Quantities
Purchase of minerals in place			30,916

Supplemental Oil and Gas Info_6

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018
Extractive Industries
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 Info_7

Supplemental Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures
Future cash inflows	$ 21,269,502	$ 16,967,369	$ 4,434,117
Future production costs	(3,440,203)	(3,305,941)	(1,220,067)
Future development costs	(5,168,271)	(4,008,916)	(1,146,632)
Future income tax expense	(2,398,612)	(1,814,510)	(442,285)
Future net cash flows for estimated timing of cash flows	10,262,416	7,838,002	1,625,133
10% annual discount for estimated timing of cash flows	(6,144,980)	(4,994,097)	(1,082,092)
Standardized measure of discounted future net cash flows	$ 4,117,436	$ 2,843,905	$ 543,041	$ 451,930

Supplemental Oil and Gas Info_8

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Principal Sources Of Change In Standardized Measure Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves
Beginning of year	$ 2,843,905	$ 543,041	$ 451,930
Sale of oil and natural gas produced, net of production costs	(822,471)	(351,031)	(104,596)
Purchase of minerals in place	4,313	507,095	188,317
Sales of minerals in place	(319,858)
Extensions and discoveries	1,829,564	1,595,385	168,796
Changes in income taxes, net	(277,050)	(488,484)	(206,817)
Changes in prices and costs	1,380,323	398,713	(57,034)
Previously estimated development costs incurred	67,575	49,977	15,067
Net changes in future development costs	(13,317)	(87,375)	11,985
Revisions of previous quantities	(1,057,523)	653,567	3,943
Accretion of discount	323,927	74,999	103,000
Change in production rates and other	158,048	(51,982)	(31,550)
End of year	$ 4,117,436	$ 2,843,905	$ 543,041

Supplemental Oil and Gas Info_9

Supplemental Oil and Gas Information - Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area
Accumulated depletion, depreciation and amortization	$ (498,811)	$ (362,406)	$ (196,567)
Total	2,959,087	2,637,322	1,377,281
Evaluated
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area
Evaluated/Unevaluated oil and natural gas properties	2,764,875	2,265,525	1,144,857
Unevaluated
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area
Evaluated/Unevaluated oil and natural gas properties	$ 693,023	$ 734,203	$ 428,991

Supplemental Oil and Gas Inf_10

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil And Gas Exploration And Production Industries Disclosures
Property acquisition costs, proved	$ 4,422	$ 269,429	$ 230,910
Property acquisition costs, unproved	85,863	386,515	235,652
Exploration and extension well costs	11,979	16,076	72,875
Development	927,985	795,273	63,006
Total	$ 1,030,249	$ 1,467,293	$ 602,443

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event - USD ($) shares in Millions, $ in Millions	Feb. 01, 2019	Feb. 28, 2019
Subsequent Events
Financial advisory fees	$ 23.1
WRD Revolving Credit Facility | 6.875% Senior Unsecured Notes, Due February 2025
Subsequent Events
Period after the consumation of the merger during which, if the senior notes are downgraded, constitutes a change in control	90 days
Percent of principal amount that is required to be offered to repurchase the notes	101.00%
Period after downgrade of notes that an offer to repurchase must be made	30 days
Chesapeake | Wildhorse Resource Development Corporation
Subsequent Events
Business acquisition, shares issued		717.3
Cash paid		$ 381.1