Brazos Valley Longhorn, L.L.C. 10-Q 8 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Entity Registrant Name	WildHorse Resource Development Corp
Entity Central Index Key	1,681,714
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		101,995,729

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 1,745	$ 226
Accounts receivable, net	111,354	84,103
Derivative instruments	0	2,336
Prepaid expenses and other current assets	5,734	3,290
Total current assets	118,833	89,955
Property and equipment:
Oil and gas properties	3,271,422	2,999,728
Other property and equipment	79,120	53,003
Accumulated depreciation, depletion and amortization	(426,373)	(368,245)
Total property and equipment, net	2,924,169	2,684,486
Other noncurrent assets:
Derivative instruments	574	86
Debt issuance costs	3,301	3,573
Other	17,575	0
Total assets	3,064,452	2,778,100
Current liabilities:
Accounts payable	66,423	53,005
Accrued liabilities	169,665	199,952
Derivative instruments	131,539	58,074
Total current liabilities	367,627	311,031
Noncurrent liabilities:
Long-term debt	1,085,997	770,596
Asset retirement obligations	7,899	14,467
Deferred tax liabilities	44,141	71,470
Derivative instruments	81,736	18,676
Other	762	1,085
Total noncurrent liabilities	1,220,535	876,294
Total liabilities	1,588,162	1,187,325
Commitments and contingencies (Note 18)	0	0
Series A perpetual convertible preferred stock, $0.01 par value: 500,000 shares authorized; 435,000 shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively, (involuntary liquidation preference of $450,389 and $448,146 at September 30, 2018 and December 31, 2017, respectively)	447,726	445,483
Stockholders' equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 101,996,754 shares and 101,137,277 shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively	1,020	1,012
Additional paid-in capital	1,146,149	1,118,507
Accumulated earnings (deficit)	(118,605)	25,773
Total stockholders' equity	1,028,564	1,145,292
Total liabilities and equity	$ 3,064,452	$ 2,778,100

UNAUDITED CONDENSED CONSOLIDA_2

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	101,996,754	101,137,277
Common stock, shares outstanding	101,996,754	101,137,277
Series A Perpetual Convertible Preferred Stock
Convertible preferred stock, par value	$ 0.01	$ 0.01
Convertible preferred stock, shares authorized	500,000	500,000
Convertible preferred stock, shares issued	435,000	435,000
Convertible preferred stock, shares outstanding	435,000	435,000
Convertible preferred stock, involuntary liquidation preference	$ 450,389	$ 448,146

UNAUDITED STATEMENTS OF CONDENS

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues and other income:
Other Income	$ 269	$ 308	$ 1,816	$ 1,244
Total operating revenues and other income	259,490	122,486	703,660	246,951
Operating expenses:
Lease operating expenses	14,221	12,435	42,736	26,200
Gathering, processing and transportation	3,225	3,761	5,053	7,403
Taxes other than income tax	14,193	6,047	38,753	14,455
Depreciation, depletion and amortization	74,842	51,843	205,419	111,515
Impairment of NLA Disposal Group (Note 3)	0	0	214,274	0
(Gain) loss on sale of properties	217	0	(2,950)	0
General and administrative expenses	16,033	11,043	41,677	28,574
Incentive unit compensation expense	0	0	13,776	0
Exploration expense	13,814	4,749	19,891	17,868
Other operating (income) expense	169	9	938	53
Total operating expense	136,714	89,887	579,567	206,068
Income (loss) from operations	122,776	32,599	124,093	40,883
Other income (expense):
Interest expense, net	(15,718)	(8,749)	(43,027)	(20,953)
Gain (loss) on derivative instruments	(76,358)	(40,288)	(227,533)	37,119
Other income (expense)	(122)	(12)	(272)	12
Total other income (expense)	(92,198)	(49,049)	(270,832)	16,178
Income (loss) before income taxes	30,578	(16,450)	(146,739)	57,061
Income tax benefit (expense)	(19,055)	5,646	28,394	(21,247)
Net income (loss) available to WRD	11,523	(10,804)	(118,345)	35,814
Preferred stock dividends	6,756	6,450	22,106	6,523
Undistributed earnings allocated to participating securities	1,233	0	0	3,234
Net income (loss) available to common stockholders	$ 3,534	$ (17,254)	$ (140,451)	$ 26,057
Earnings per common share:
Basic	$ 0.04	$ (0.17)	$ (1.41)	$ 0.27
Diluted	$ 0.04	$ (0.17)	$ (1.41)	$ 0.27
Weighted-average common shares outstanding:
Basic	99,639	99,142	99,433	95,369
Diluted	99,639	99,142	99,433	95,369
Oil sales
Revenues and other income:
Revenues	$ 236,040	$ 100,391	$ 625,811	$ 192,431
Natural gas sales
Revenues and other income:
Revenues	9,298	14,906	45,034	40,328
Natural gas liquid sales
Revenues and other income:
Revenues	$ 13,883	$ 6,881	$ 30,999	$ 12,948

UNAUDITED STATEMENTS OF CONDE_2

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income (loss)	$ (118,345)	$ 35,814
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	205,419	111,515
Impairments of unproved properties	8,226	13,910
Impairment of NLA Disposal Group	214,274	0
Amortization of debt issuance cost	2,184	1,962
Accretion of senior note discount	108	197
(Gain) loss on derivative instruments	227,533	(37,119)
Cash settlements on derivative instruments	(81,177)	6,895
Deferred income tax expense (benefit)	(27,396)	20,263
Debt extinguishment benefit		(11)
Amortization of equity awards	11,988	4,217
Incentive unit compensation expense	13,776	0
(Gain) loss on sale of properties	(2,950)	0
Loss on equity investment	103
Consideration paid to customers, net of amortization	(1,806)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	(23,492)	(42,081)
Decrease (increase) in prepaid expenses	(503)	(1,245)
Decrease (increase) in inventories	648
(Decrease) increase in accounts payable and accrued liabilities	18,784	28,875
Net cash flow provided by operating activities	447,374	143,192
Cash flows from investing activities:
Acquisitions of oil and gas properties	(53,188)	(549,033)
Additions to oil and gas properties	(824,656)	(443,210)
Additions to and acquisitions of other property and equipment	(57,987)	(10,070)
Construction deposits	(1,714)
Contribution to equity method investee	(10,177)
Proceeds from NLA Divestiture	206,406
Net cash used in investing activities	(741,316)	(1,002,313)
Cash flows from financing activities:
Advances on revolving credit facilities	842,000	363,500
Payments on revolving credit facilities	(729,353)	(447,765)
Debt issuance cost	(3,502)	(13,545)
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
Cost incurred in conjunction with the issuance of stock		(2,698)
Preferred stock dividends	(13,512)
Repurchase of vested restricted stock	(4,172)
Net cash provided by financing activities	295,461	861,031
Net change in cash, cash equivalents and restricted cash	1,519	1,910
Cash, cash equivalents and restricted cash, beginning of period	226	4,001
Cash, cash equivalents and restricted cash, end of period	$ 1,745	5,911
Convertible Preferred Stock
Cash flows from financing activities:
Cost incurred in conjunction with the issuance of stock		$ (2,662)

UNAUDITED CONDENSED CONSOLIDA_3

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Common Stock	Additional Paid in Capital	Accumulated Earnings (Deficit)	Total
Balance at Dec. 31, 2016	$ 917	$ 1,017,368	$ (10,397)	$ 1,007,888
Net income (loss)			20,252	20,252
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		495		495
Balance at Mar. 31, 2017	940	1,050,425	9,855	1,061,220
Balance at Dec. 31, 2016	917	1,017,368	(10,397)	1,007,888
Net income (loss)				35,814
Balance at Sep. 30, 2017	1,012	1,114,829	18,894	1,134,735
Balance at Mar. 31, 2017	940	1,050,425	9,855	1,061,220
Net income (loss)			26,366	26,366
Issuance of common stock in connection with the Acquisition	55	60,699		60,754
Preferred stock paid-in-kind dividend			(73)	(73)
Amortization of equity awards	16	1,292		1,308
Balance at Jun. 30, 2017	1,011	1,112,416	36,148	1,149,575
Net income (loss)			(10,804)	(10,804)
Preferred stock paid-in-kind dividend			(6,450)	(6,450)
Amortization of equity awards	1	2,413		2,414
Balance at Sep. 30, 2017	1,012	1,114,829	18,894	1,134,735
Balance at Dec. 31, 2017	1,012	1,118,507	25,773	1,145,292
Net income (loss)			(115,774)	(115,774)
Preferred stock paid-in-kind dividend			(2,243)	(2,243)
Accrued preferred stock cash dividend			(4,480)	(4,480)
Beneficial conversion feature of preferred stock		1,872		1,872
Amortization of beneficial conversion feature			(668)	(668)
Repurchase of vested restricted common stock			(69)	(69)
Amortization of equity awards	1	3,155		3,156
Balance at Mar. 31, 2018	1,013	1,123,534	(97,220)	1,027,327
Balance at Dec. 31, 2017	1,012	1,118,507	25,773	1,145,292
Net income (loss)				(118,345)
Balance at Sep. 30, 2018	1,020	1,146,149	(118,605)	1,028,564
Cumulative effect of accounting change (Note 2) | Restatement Adjustment | Accounting Standards Update 2014-09			241	241
Balance at Mar. 31, 2018	1,013	1,123,534	(97,220)	1,027,327
Net income (loss)			(14,094)	(14,094)
Preferred stock cash dividend			(6,756)	(6,756)
Accrued preferred stock cash dividend			1	1
Amortization of beneficial conversion feature			(1,204)	(1,204)
Contribution related to incentive unit compensation expense		13,776		13,776
Repurchase of vested restricted common stock	(2)		(4,034)	(4,036)
Amortization of equity awards	9	3,830		3,839
Balance at Jun. 30, 2018	1,020	1,141,140	(123,305)	1,018,855
Cumulative effect of accounting change (Note 2) | Restatement Adjustment | Accounting Standards Update 2014-09			2	2
Net income (loss)			11,523	11,523
Preferred stock cash dividend			(6,756)	(6,756)
Repurchase of vested restricted common stock			(67)	(67)
Amortization of equity awards		5,009		5,009
Balance at Sep. 30, 2018	$ 1,020	$ 1,146,149	$ (118,605)	$ 1,028,564

Organization and Basis of Prese

Organization and Basis of Presentation	9 Months Ended
	Sep. 30, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation WildHorse Resource Development Corporation is a publicly traded Delaware corporation, the common stock of which are listed on the New York Stock Exchange under the symbol “WRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “WRD,” or “the Company” are intended to mean the business and operations of WildHorse Resource Development Corporation and its consolidated subsidiaries. We are an independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources in the United States of America. Reference to “WHR II” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries. Reference to “Esquisto II” refers to Esquisto Resources II, LLC. Reference to “Acquisition Co.” refers to WHE AcqCo., LLC. Reference to “WildHorse Investment Holdings” refers to WildHorse 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 II and Acquisition Co. 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 September 30, 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. Basis of Presentation Our consolidated 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 unaudited statements of condensed consolidated cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals within the unaudited statements of condensed consolidated cash flows due to the adoption of a new accounting standard. See Note 2 for additional information. All material intercompany transactions and balances have been eliminated in preparation of our condensed consolidated financial statements. The accompanying condensed consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). 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, 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. 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. WHCC’s 50% membership interest in JWH is subject to a call and put option. The call option gives JV Partner the right, but not the obligation, to purchase WHCC’s membership interest after December 1, 2018 in the event that WHCC and JV Partner have not entered into definitive documentation regarding a proposed joint venture terminal development plan on or before December 1, 2018. The put option gives WHCC the right, but not the obligation, to require JV Partner to purchase WHCC’s membership interest after June 1, 2019 in the event that WHCC and JV Partner have not entered into definitive documentation regarding a proposed joint venture terminal development plan on or before June 1, 2019. The predetermined sales price of WHCC’s membership interest will be equal to aggregate capital contributions made by WHCC to JWH, less any distributions made by JWH to WHCC, plus a rate of return equal to three percent. We determined that the call and put options did not meet the definition of a derivative. 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. If the put or call option is exercised, JV Partner is contractually required to take all actions, including but not limited to, providing a letter of credit or similar guarantee to the Port, as necessary to have WRD fully released from its letter of credit. 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 $10.1 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 $0.1 million for the three and nine months ended September 30, 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	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies A discussion of our significant accounting policies and estimates is included in our 2017 Form 10-K. There have been no changes except as discussed below. Oil and Gas Properties Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed. Effective July 1, 2018, we lowered our significance threshold and as a result, we excluded capitalized costs of $60.9 million at September 30, 2018. Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 45,496 $ 13,465 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (45,838) 95,292 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (1,780) 7,990 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. Early adoption was permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. 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. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. Originally, entities were required to use a modified retrospective approach, where the date of initial application to existing leases would be to the beginning of the earliest period presented in the annual financial statements where we first apply the new standard (i.e. financial statements as of and for the year ending December 31, 2019). Under this method therefore, leases commencing as early as January 1, 2017 would be impacted by the new standard and comparative periods presented in those financials would likely be adjusted (“the comparative method”). 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 currently intends to adopt the standard using the effective date method. 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 current 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 currently intends to make this accounting policy election upon adoption. 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 currently intends to make this accounting policy election for most or all classes of assets. 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 currently intends to make this accounting policy election upon adoption. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. Though the full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption, we have determined that the adoption of the standard will result in a material increase to our assets and liabilities due to the recognition on our balance sheet of our office leases and certain equipment. As we complete our evaluation, we will determine all contracts that are impacted throughout our various disciplines. 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, WildHorse 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 WildHorse 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 September 30, 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), 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 Three Months Ended September 30, 2018 For the Nine Months Ended September 30, 2018 As Reported Without ASC 606 Increase/- As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Under ASC 606 Adoption Decrease Revenues: Oil sales $ 236,040 $ 236,056 $ (16) $ 625,811 $ 625,856 $ (45) Natural gas sales 9,298 10,378 (1,080) 45,034 48,353 (3,319) NGL sales 13,883 16,125 (2,242) 30,999 37,727 (6,728) Other Income 269 269 — 1,816 1,625 191 Operating expenses: Lease operating expenses 14,221 14,681 (460) 42,736 43,736 (1,000) Gathering, processing and transportation 3,225 6,246 (3,021) 5,053 14,366 (9,313) Depreciation, depletion and amortization 74,842 75,023 (181) 205,419 205,889 (470) Other operating (income) expense 169 1 168 938 460 478 Income (loss) before income taxes 30,578 30,422 156 (146,739) (147,142) 403 Income tax benefit (expense) (19,055) (19,022) (33) 28,394 28,481 (87) Net income (loss) 11,523 11,400 123 (118,345) (118,661) 316 At September 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,271,422 $ 3,277,335 $ (5,913) Accumulated depreciation, depletion and amortization (426,373) (427,213) 840 Other non-current assets 17,575 11,792 5,783 Liabilities: Deferred tax liabilities 44,141 43,988 153 Stockholders' Equity Accumulated earnings (deficit) (118,605) (117,741) (864) For the Nine Months Ended September 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ (118,345) $ (118,661) $ 316 Depreciation, depletion and amortization 205,419 205,889 (470) Deferred income tax expense (benefit) (27,396) (27,483) 87 Consideration paid to customers, net of amortization (1,806) — (1,806) Cash flows from investing activities: Additions to oil and gas properties (824,656) (826,528) 1,872 Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on our consolidated financial statements and footnote disclosures.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2018
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Acquisition-related costs Acquisition-related costs accounted for as business combinations are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 $ 424 $ 998 $ 912 $ 3,796 2018 Acquisitions Eagle Ford Acquisitions. During the nine months ended September 30, 2018, we closed on multiple transactions to acquire certain acreage and associated production from third parties for approximately $53.2 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 $1.0 million of acquisition costs were capitalized as part of these acquisitions. We assigned $48.2 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 $44.5 million at September 30, 2018. In addition, we have $1.7 million of unapplied construction deposits that were paid during the nine months ended September 30, 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 Anadarko E&P Onshore LLC (“APC”) and Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “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”). On June 30, 2017, we completed the Acquisition. Consideration consisted of approximately $533.6 million in cash and approximately 5.5 million shares of our common stock. The common stock was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017, by and among us and KKR. We finalized our purchase price allocation during the first quarter of 2018 and received a $0.6 million cash payment from the Sellers on February 1, 2018. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed after customary purchase price adjustments 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 nine months ended September 30, 2017 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 statements of operations 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 Nine Months Ended September 30, 2017 Revenues $ 295,160 Net income (loss) 57,221 Earnings per share (basic and diluted) 0.47 Burleson 2017 Acquisitions. During the nine months ended September 30, 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 $19.3 million, of which $11.6 million was allocated to unproved oil and natural gas properties. 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 $21.7 million previously received as a deposit, which included preliminary purchase price adjustments of approximately $0.9 million related to certain assets that were retained pending receipt of a consent to assign certain assets at the initial closing and approximately $9.7 million related to the net cash flows from the effective date to the closing date (the “NLA Divestiture”). We received the necessary consent to assign approximately $0.9 million of NLA Assets and assigned such NLA Assets to Tanos on August 1, 2018. In addition, WRD could receive contingent payments of up to $35.0 million, of which $0.4 million has been accrued at September 30, 2018, based on the number of wells spud on such properties over the next four 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. In October 2018, 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 nine months ended September 30, 2018 and 2017, the NLA Disposal Group had pre-tax losses of $202.2 million and $6.8 million, respectively. During the nine months ended September 30, 2018, we recognized an estimated gain of $3.0 million which we expect to realize upon final settlement. We have recorded a $4.8 million final settlement receivable from Tanos at September 30, 2018, all of which was received 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	9 Months Ended
	Sep. 30, 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). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. 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 September 30, 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 September 30, 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 September 30, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Fair Value Measurements at September 30, 2018 Using Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 574 $ — $ 574 Liabilities: Commodity derivatives $ — $ 213,275 $ — $ 213,275 Fair Value Measurements at December 31, 2017 Using 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 natural gas properties. We did not record impairments to proved oil and natural gas properties during the three and nine months ended September 30, 2018 and 2017. · Unproved oil and natural gas properties 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 three and nine months ended September 30, 2018, we recorded $2.4 million and $8.2 million of impairments of unproved properties, respectively. We recorded $3.2 million and $13.9 million of impairments of unproved properties for the three and nine months ended September 30, 2017, respectively. · We recorded an impairment associated with the NLA Assets during the first quarter of 2018. See Note 3—“Acquisitions and Divestitures—2018 Divestiture” for additional information.

Risk Management and Derivative

Risk Management and Derivative Instruments	9 Months Ended
	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments We have entered into certain derivative arrangements with respect to portions of our oil and natural gas production to reduce our sensitivity to volatile commodity prices. None of our derivative instruments are designated as cash flow hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve more predictable cash flows and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil and natural gas sales. Moreover, our derivative arrangements apply only to a portion of our production and provide only partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our risk management program in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements. Commodity Derivatives We have fixed price commodity swaps, basis swaps, 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. 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 paid or received on settled derivative positions during the nine months ended September 30, 2018 and 2017 is net of deferred premiums of $6.1 million and $2.1 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, all of which are also lenders under our 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 September 30, 2018 we had net derivative liabilities of $212.7 million and we did not have a right of offset as we were in a net liability position with all of our counterparties. See “Note 4—Fair Value Measurements of Financial Instruments” for further information. The following derivative contracts were in place at September 30, 2018: Remainder 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 1,398,947 6,652,369 4,511,681 Weighted-average fixed price $ 52.33 $ 54.45 $ 53.49 Put options: Volume (Bbls) 989,379 1,749,757 — Weighted-average floor price $ 49.55 $ 53.83 $ — Weighted-average put premium $ (3.69) $ (5.43) $ — LLS basis swaps: Volume (Bbls) 1,711,789 — — Spread-WTI $ 3.02 $ — $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 2,184,376 6,425,146 4,846,020 Weighted-average fixed price $ 2.79 $ 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 September 30, 2018 and December 31, 2017 (in thousands). There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives September 30, December 31, September 30, December 31, Type Balance Sheet Location 2018 2017 2018 2017 Commodity contracts Short-term derivative instruments $ — $ 2,336 $ 131,539 $ 58,074 Netting arrangements Short-term derivative instruments — — — — Net recorded fair value $ — $ 2,336 $ 131,539 $ 58,074 Commodity contacts Long-term derivative instruments $ 574 $ 86 $ 81,736 $ 18,676 Netting arrangements Long-term derivative instruments — — — — Net recorded fair value $ 574 $ 86 $ 81,736 $ 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 Unaudited Statements of Condensed Consolidated Operations. The following table details the gains and losses related to derivative instruments for the three and nine months ending September 30, 2018 and 2017 (in thousands): Statements of For the Three Months Ended September 30, For the Nine Months Ended September 30, Operations Location 2018 2017 2018 2017 Commodity derivative contracts Gain (loss) on derivative instruments $ (76,358) $ (40,288) $ (227,533) $ 37,119

Accounts Receivable

Accounts Receivable	9 Months Ended
	Sep. 30, 2018
Receivables [Abstract]
Accounts Receivable	Note 6. Accounts Receivable Accounts receivable consist of the following (in thousands): September 30, December 31, 2018 2017 Oil, gas and NGL sales $ 83,674 $ 67,584 Joint interest billings 18,129 9,467 Severance tax 304 171 North Louisiana Settlement receivable — 5,955 Environmental remediation 1,511 — Other current receivables 2,672 1,026 NLA Divestiture 5,264 — Allowance for doubtful accounts (200) (100) Total $ 111,354 $ 84,103 The following table presents our allowance for doubtful accounts activity for the nine months ended September 30, 2018 (in thousands): Balance at beginning of period $ 100 Charged to costs and expenses 100 Balance at end of period $ 200

Accrued Liabilities

Accrued Liabilities	9 Months Ended
	Sep. 30, 2018
Payables And Accruals [Abstract]
Accrued Liabilities	Note 7. Accrued Liabilities Accrued liabilities consist of the following (in thousands): September 30, December 31, 2018 2017 Capital expenditures $ 121,123 $ 162,260 Preferred stock cash dividends 4,479 — Lease operating expense 5,410 5,796 General and administrative 9,150 1,642 Severance and ad valorem taxes 9,265 3,463 Interest expense 8,190 17,177 Derivative payable 11,919 5,281 Income taxes — 991 Other accrued liabilities 129 3,342 Total $ 169,665 $ 199,952

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 8. Asset Retirement Obligations The Company’s AROs primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2018 (in thousands): Asset retirement obligations at beginning of period $ 14,557 Accretion expense 448 Liabilities incurred 611 Disposition of wells and gathering system (7,627) Asset retirement obligations at end of period 7,989 Less: current portion 90 Asset retirement obligations – long-term $ 7,899

Long Term Debt

Long Term Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long Term Debt	Note 9. Long Term Debt Our debt obligations consisted of the following at the dates indicated (in thousands): September 30, December 31, Debt Obligation 2018 2017 WRD revolving credit facility $ 399,000 $ 286,353 2025 Senior Notes (as defined below) (1) 700,000 500,000 Unamortized net discounts - 2025 Senior Notes (805) (4,914) Unamortized debt issuance costs - 2025 Senior Notes (12,198) (10,843) Total long-term debt $ 1,085,997 $ 770,596 (1) The estimated fair value of this fixed-rate debt was $722.8 million and $511.3 million at September 30, 2018 and December 31, 2017, respectively. The estimated fair values are based on quoted market prices and are 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): September 30, Credit Facility 2018 WRD revolving credit facility $ 1,050,000 Letter of Credit See “Note 1—Organization and Basis of Presentation—Investment in Unconsolidated Affiliate” for information related to our $47.5 million letter of credit outstanding. Amendment to Credit Agreement 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 (the “Fourth Amendment”) to the Credit Agreement 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 Fourth Amendment, among other things, modified the Credit Agreement to increase the borrowing base from $875.0 million to $1.05 billion. Subsequent Event. 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 (the “Fifth Amendment”) to the Credit Agreement. 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 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. 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 Securities and Exchange Commission (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 variable-rate debt obligations for the periods presented: For the Three Months Ended September 30, For the Nine Months Ended September 30, Credit Facility 2018 2017 2018 2017 WRD revolving credit facility 4.12 % 3.71 % 4.02 % 3.63 % Unamortized Debt Issuance Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands): September 30, December 31, 2018 2017 WRD revolving credit facility Current $ 1,486 $ 1,203 Long-term 3,301 3,573 6.875% senior unsecured notes, due February 2025 12,198 10,843 Total $ 16,985 $ 15,619

Preferred Stock

Preferred Stock	9 Months Ended
	Sep. 30, 2018
Temporary Equity [Abstract]
Preferred Stock	Note 10. Preferred Stock The following is a summary of the changes in our preferred stock for the nine months ended September 30, 2018: Series A Perpetual Convertible Preferred Stock (in thousands) Balance at December 31, 2017 $ 445,483 Accrual of paid-in-kind dividend 2,243 Beneficial conversion feature ("BCF") (1,872) Amortization of BCF 1,872 Balance at September 30, 2018 $ 447,726 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 January 31, 2018, an aggregate quarterly dividend of $6.656 million on our outstanding shares of preferred stock was paid by an automatic increase to the Accreted Value (as defined in the Certificate of Designations 6.00% Series A Perpetual Convertible Preferred Stock) of each such share of preferred stock as of the date of issuance. The declared dividend was for the period from 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 BCF that was fully amortized as of June 30, 2018. 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 Subsequent Event. On October 31, 2018, an aggregate quarterly cash dividend of $6.756 million was paid to holders of record as of October 15, 2018 for the period from August 1, 2018 to October 31, 2018.

Equity

Equity	9 Months Ended
	Sep. 30, 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 stock issued for the nine months ended September 30, 2018: Balance, December 31, 2017 101,137,277 Restricted common shares issued 1,076,165 Restricted common shares forfeited (60,911) Repurchase of vested restricted shares (1) (155,777) Balance, September 30, 2018 101,996,754 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Shareholders surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for employee tax obligations to the appropriate taxing authorities were approximately $4.2 million for the nine months ended September 30, 2018. The net-settlements had the effect of share repurchases by the Company as they reduced the number of shares that would have otherwise been outstanding due to the vesting and did not represent an expense to the Company. See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted during the nine months ended September 30, 2018. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 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 three and nine months ended September 30, 2018 and 2017 (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 Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 Numerator: Net income (loss) available to WRD $ 11,523 $ (10,804) $ (118,345) $ 35,814 Less: Preferred stock dividends 6,756 6,450 22,106 6,523 Less: Undistributed earnings allocated to participating securities 1,233 — — 3,234 Net income (loss) available to common stockholders $ 3,534 $ (17,254) $ (140,451) $ 26,057 Denominator: Weighted-average common shares outstanding (in thousands) (1) (2) 99,639 99,142 99,433 95,369 Basic EPS $ 0.04 $ (0.17) $ (1.41) $ 0.27 Diluted EPS (1) (2) $ 0.04 $ (0.17) $ (1.41) $ 0.27 (1) The Company used the two-class method for both basic and diluted EPS. Restricted shares were excluded from the calculation of diluted EPS due to their antidilutive effect as we were in a loss position for the nine months ended September 30, 2018. For the three months ended September 30, 2018, 546 incremental restricted shares were excluded in the calculation of diluted EPS under the treasury stock method. For the three and nine months ended September 30, 2018, 32,402 shares and 32,349 shares, were excluded in 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 three months ended September 30, 2017, restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect as we were in a loss position. For the nine months ended September 30, 2017, 481 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the three and nine months ended September 30, 2017, 10,696 and 31,400 shares, respectively, were excluded in the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

Long Term Incentive Plans

Long Term Incentive Plans	9 Months Ended
	Sep. 30, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Long Term Incentive Plans	Note 13. Long Term Incentive Plans In connection with our initial public offering, our board of directors 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 stock awards granted under the 2016 LTIP for the periods presented: Weighted-Average Number of Grant Date Fair Shares Value per Share (1) Restricted common stock outstanding at December 31, 2017 1,897,790 $ 13.95 Granted (2) 1,076,165 $ 25.57 Forfeited (60,911) $ 16.03 Vested (561,581) $ 13.88 Restricted common stock outstanding at September 30, 2018 2,351,463 $ 19.23 (1) Determined by dividing the aggregate grant date fair value of stock subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common stock awards granted in 2018 was $27.5 million based on the grant date market price of ranging from $18.14 to $27.07 per share. For the three months ended September 30, 2018 and 2017, we recorded $5.0 million and $2.4 million of recognized compensation expense, respectively, associated with these awards. For the nine months ended September 30, 2018 and 2017, we recorded $12.0 million and $4.2 million of recognized compensation expense, respectively, associated with these awards. Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $36.3 million at September 30, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.

Incentive Units

Incentive Units	9 Months Ended
	Sep. 30, 2018
Compensation Related Costs [Abstract]
Incentive Units	Note 14. Incentive Units C ertain officers and employees have been granted awards of incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (the “LLCs”). Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings and the LLCs. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date 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 September 30, 2018. Under the respective limited liability company agreements of WildHorse Investment Holdings and the LLCs, WildHorse Investment Holdings and the LLCs are obligated to provide to the holders of incentive units, including named executive officers, a portion of their respective distributions, but only after a substantial priority distribution, the amount of which is specified in each respective limited liability company agreement and is referred to as a "distribution threshold," has first been made to the holders of capital interests in WildHorse Investment Holdings and the LLCs (who are the investors in these entities). The distribution threshold differs with regard to each class (referred to as a "tier") of incentive units in WildHorse Investment Holdings (which has five tiers) and the LLCs (each of which has two tiers). As the only assets of the LLCs are shares of our common stock, any distributions to the named executive officers holding incentive units in the LLCs would be dependent on distributions of cash proceeds of sales of shares of our common stock or distribution of our common stock to holders of capital interests sufficient in amount to exceed the applicable distribution threshold, thereby enabling the commencement of participation by holders of incentive units in additional distributions. 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). Upon and subject to the consummation of our merger with Chesapeake, all unvested incentive units will become fully vested in accordance with their terms and will remain outstanding following the effective time of such merger. See “Note 19—Subsequent Events” for information regarding our merger with Chesapeake.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Note 15. Related Party Transactions 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. During the three months ended September 30, 2017, we received $0.5 million from Genesis. We did not have any purchases from Genesis for the three months ended September 30, 2018. We received $1.2 million and $1.9 million for the nine months ended September 30, 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. We had disbursements of $0.1 million to Archrock for the nine months ended September 30, 2018. 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 three and nine months ended September 30, 2017, we had net disbursements of less than $0.1 million and $0.1 million, respectively, related to director and advisory fees and reimbursement of initial public offering costs. We did not have any related party payments or receipts due to or from NGP ECM for the three and nine months ended September 30, 2018. Cretic Energy Services, LLC. During the three and nine months ended September 30, 2017, we had disbursements of $0.1 million and $0.2 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. We did not have any related party payments to Cretic Energy Services, LLC for the three and nine months ended September 30, 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 three and nine months ended September 30, 2018 we had disbursements of less than $0.1 million and $0.2 million, respectively, to certain CH4 Energy entities for office rental and parking payments. During the three and nine months ended September 30, 2017 we had disbursements of $0.1 million and $0.5 million to certain CH4 Energy entities, respectively. For the nine months ended September 30, 2017, $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. Related Party Agreements Stockholders’ Agreement A discussion of this agreement is included in our 2017 Form 10-K. Registration Rights Agreement A discussion of this agreement is included in our 2017 Form 10-K. Transition Services Agreement Upon the closing of our initial public offering, we entered into a transition services agreement with CH4 Energy IV, LLC, Petromax and Crossing Rocks Energy, LLC (collectively, the “Service Providers”), pursuant to which the Service Providers agreed to provide certain engineering, land, operating and financial services to us for six months relating to our Eagle Ford Acreage. In exchange for such services, we agreed to pay a monthly management fee to the Service Providers. NGP and certain former management members of Esquisto own the Service Providers. The transition service agreement was terminated on March 31, 2017 and $0.1 million was paid to the Service Providers during the nine months ended September 30, 2017.

Segment Disclosures

Segment Disclosures	9 Months Ended
	Sep. 30, 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 September 30, 2018, we identified one operating segment and one reportable segment—the Eagle Ford—that is engaged in the acquisition, exploitation, 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 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. The Company uses Adjusted EBITDAX, a non-GAAP financial measure, as its measure of profit or loss to assess performance and allocate resources. Information regarding assets by reportable segment is not presented because it is not reviewed by the CODM. The following table presents a reconciliation of Net income (loss) to Adjusted EBITDAX (in thousands): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 11,523 $ (10,804) $ (118,345) $ 35,814 Interest expense, net 15,718 8,749 43,027 20,953 Income tax (benefit) expense 19,055 (5,646) (28,394) 21,247 Depreciation, depletion and amortization 74,842 51,843 205,419 111,515 Exploration expense 13,814 4,749 19,891 17,868 Impairment of NLA Disposal Group — — 214,274 — (Gain) loss on derivative instruments 76,358 40,288 227,533 (37,119) Cash settlements received (paid) on derivative instruments (31,123) 5,802 (81,177) 6,895 Stock-based compensation 4,997 2,414 11,988 4,217 Incentive unit compensation — — 13,776 — Acquisition related costs 424 998 912 3,796 (Gain) loss on sale of properties 217 — (2,950) — Debt extinguishment costs — — — (11) Initial public offering costs — — — 182 Total Adjusted EBITDAX $ 185,825 $ 98,393 $ 505,954 $ 185,357

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 17. Income Taxes The Company is a corporation subject to federal and state income taxes. The Company records its tax provision in interim periods using the estimated annual effective tax rate. Discrete items are excluded from the Company’s estimated annual effective tax rate and income tax effects associated with discrete items are recognized in the period in which they occur. We have a $2.3 million federal income tax refund at September 30, 2018 recorded as a component of “Prepaid expenses and other current assets” on our balance sheet. The Company recorded income tax expense of $19.1 million and an income tax benefit of $5.6 million for the three months ended September 30, 2018 and 2017, respectively. The change is primarily due to the pretax income in 2018 as compared to the pretax loss in 2017. The effective tax rate for the three months ended September 30, 2018 and 2017 was 62.3% and 34.3%, respectively. The increase in the effective tax rate was primarily due to state income taxes, offset by a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation enacted in December 2017. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018, primarily due to the impact of the state income tax provision related to a change in the estimated annual effective tax rate. The effective tax rate differed from the statutory federal income tax rate of 35% for 2017, primarily due to the impact of the state income tax provision. The Company recorded an income tax benefit of $28.4 million and income tax expense of $21.2 million for the nine months ended September 30, 2018 and 2017, respectively. The change is primarily due to the pretax loss in 2018 as compared to the pretax income in 2017. The effective tax rate for the nine months ended September 30, 2018 and 2017 was 19.3% and 37.2%, respectively. The decrease in the effective tax rate was primarily due to incentive unit compensation, the impact of the state income tax provision, and a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation enacted in December 2017, partially offset by an excess tax benefit associated with stock-based compensation, and state tax adjustments associated with the NLA Divestiture. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018, primarily due to incentive unit compensation, stock-based compensation, state tax adjustments associated with the NLA Divestiture, and the state income tax provision. The effective tax rate differed from the statutory federal income tax rate of 35% for 2017, primarily due to the impact of the state income tax provision. The Company reported no liability for unrecognized tax benefits as of September 30, 2018 and expects no significant change to the unrecognized tax benefits in the next twelve months.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 18. Commitments and Contingencies Lease Obligations We executed two office leases during the nine months ended September 30, 2018. In June 2018, we executed a new lease for corporate office space that has escalating payments. The estimated commencement date is January 1, 2019 and the lease terminates on December 31, 2026. The lease for our current corporate office is expected to terminate on December 31, 2018. 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. The table below reflects our estimated minimum commitments as of September 30, 2018 related to our office leases (in thousands): Remaining 2018 2019 2020 2021 2022 Thereafter Office Leases $ 390 $ 2,249 $ 2,285 $ 2,254 $ 2,066 $ 8,621 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 September 30, 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. 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 September 30, 2018 and at December 31, 2017. Firm Gas Transportation Service Agreement The Company had a firm gas transportation service agreement with Regency Intrastate Gas LLC as discussed in our 2017 Form 10-K. In connection with the NLA Divestiture, we transferred this agreement to Tanos. Dedicated Fracturing Fleet Services Agreements A discussion of these agreements are included in our 2017 Form 10-K. 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 nine months ended September 30, 2018 and 2017, respectively.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 19. Subsequent Events Proposed Merger with Chesapeake Energy Corporation On October 30, 2018, we jointly announced with Chesapeake that we entered into a definitive agreement to merge with Chesapeake, an independent exploration and production company engaged in the acquisition, exploration and development of properties in the Eagle Ford Shale in South Texas, the stacked pay in the Powder River Basin in Wyoming, the Anadarko Basin in northwestern Oklahoma, the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana and East Texas, for the production of oil, natural gas and NGLs from underground reservoirs. At the election of each Company stockholder, Chesapeake will acquire each outstanding share of the Company in exchange for either 5.989 shares of Chesapeake common stock, $0.01 par value per share, or a combination of 5.336 shares of Chesapeake common stock and $3.00 cash. The merger, which is expected to close in the first half of 2019, has been unanimously approved by the board of directors of each company and is subject to stockholder approvals from both companies, customary closing conditions and regulatory approvals. Quarterly Preferred Stock Dividend See Note 10—“Preferred Stock” for information regarding quarterly dividends paid on our outstanding preferred stock. Fifth Amendment to the Credit Agreement See Note 9—“Long Term Debt” for information regarding the Fifth Amendment, which was entered into on October 15, 2018.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our consolidated 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 unaudited statements of condensed consolidated cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals within the unaudited statements of condensed consolidated cash flows due to the adoption of a new accounting standard. See Note 2 for additional information. All material intercompany transactions and balances have been eliminated in preparation of our condensed consolidated financial statements. The accompanying condensed consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
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, 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.
Equity Method Investments	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.
Oil and Gas Properties	Oil and Gas Properties Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed. Effective July 1, 2018, we lowered our significance threshold and as a result, we excluded capitalized costs of $60.9 million at September 30, 2018.
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 45,496 $ 13,465 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (45,838) 95,292 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (1,780) 7,990
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. Early adoption was permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements. Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. 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. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. Originally, entities were required to use a modified retrospective approach, where the date of initial application to existing leases would be to the beginning of the earliest period presented in the annual financial statements where we first apply the new standard (i.e. financial statements as of and for the year ending December 31, 2019). Under this method therefore, leases commencing as early as January 1, 2017 would be impacted by the new standard and comparative periods presented in those financials would likely be adjusted (“the comparative method”). 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 currently intends to adopt the standard using the effective date method. 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 current 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 currently intends to make this accounting policy election upon adoption. 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 currently intends to make this accounting policy election for most or all classes of assets. 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 currently intends to make this accounting policy election upon adoption. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. Though the full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption, we have determined that the adoption of the standard will result in a material increase to our assets and liabilities due to the recognition on our balance sheet of our office leases and certain equipment. As we complete our evaluation, we will determine all contracts that are impacted throughout our various disciplines. 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, WildHorse 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 WildHorse 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 September 30, 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), 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 Three Months Ended September 30, 2018 For the Nine Months Ended September 30, 2018 As Reported Without ASC 606 Increase/- As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Under ASC 606 Adoption Decrease Revenues: Oil sales $ 236,040 $ 236,056 $ (16) $ 625,811 $ 625,856 $ (45) Natural gas sales 9,298 10,378 (1,080) 45,034 48,353 (3,319) NGL sales 13,883 16,125 (2,242) 30,999 37,727 (6,728) Other Income 269 269 — 1,816 1,625 191 Operating expenses: Lease operating expenses 14,221 14,681 (460) 42,736 43,736 (1,000) Gathering, processing and transportation 3,225 6,246 (3,021) 5,053 14,366 (9,313) Depreciation, depletion and amortization 74,842 75,023 (181) 205,419 205,889 (470) Other operating (income) expense 169 1 168 938 460 478 Income (loss) before income taxes 30,578 30,422 156 (146,739) (147,142) 403 Income tax benefit (expense) (19,055) (19,022) (33) 28,394 28,481 (87) Net income (loss) 11,523 11,400 123 (118,345) (118,661) 316 At September 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,271,422 $ 3,277,335 $ (5,913) Accumulated depreciation, depletion and amortization (426,373) (427,213) 840 Other non-current assets 17,575 11,792 5,783 Liabilities: Deferred tax liabilities 44,141 43,988 153 Stockholders' Equity Accumulated earnings (deficit) (118,605) (117,741) (864) For the Nine Months Ended September 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ (118,345) $ (118,661) $ 316 Depreciation, depletion and amortization 205,419 205,889 (470) Deferred income tax expense (benefit) (27,396) (27,483) 87 Consideration paid to customers, net of amortization (1,806) — (1,806) Cash flows from investing activities: Additions to oil and gas properties (824,656) (826,528) 1,872 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.
Contingent Consideration Arrangements	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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Schedule of Supplemental Cash Flow Information	Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 45,496 $ 13,465 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (45,838) 95,292 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (1,780) 7,990
Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Summary of Impact of Adoption of Accounting Standards	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): 111 1 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 Three Months Ended September 30, 2018 For the Nine Months Ended September 30, 2018 As Reported Without ASC 606 Increase/- As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Under ASC 606 Adoption Decrease Revenues: Oil sales $ 236,040 $ 236,056 $ (16) $ 625,811 $ 625,856 $ (45) Natural gas sales 9,298 10,378 (1,080) 45,034 48,353 (3,319) NGL sales 13,883 16,125 (2,242) 30,999 37,727 (6,728) Other Income 269 269 — 1,816 1,625 191 Operating expenses: Lease operating expenses 14,221 14,681 (460) 42,736 43,736 (1,000) Gathering, processing and transportation 3,225 6,246 (3,021) 5,053 14,366 (9,313) Depreciation, depletion and amortization 74,842 75,023 (181) 205,419 205,889 (470) Other operating (income) expense 169 1 168 938 460 478 Income (loss) before income taxes 30,578 30,422 156 (146,739) (147,142) 403 Income tax benefit (expense) (19,055) (19,022) (33) 28,394 28,481 (87) Net income (loss) 11,523 11,400 123 (118,345) (118,661) 316 At September 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,271,422 $ 3,277,335 $ (5,913) Accumulated depreciation, depletion and amortization (426,373) (427,213) 840 Other non-current assets 17,575 11,792 5,783 Liabilities: Deferred tax liabilities 44,141 43,988 153 Stockholders' Equity Accumulated earnings (deficit) (118,605) (117,741) (864) For the Nine Months Ended September 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ (118,345) $ (118,661) $ 316 Depreciation, depletion and amortization 205,419 205,889 (470) Deferred income tax expense (benefit) (27,396) (27,483) 87 Consideration paid to customers, net of amortization (1,806) — (1,806) Cash flows from investing activities: Additions to oil and gas properties (824,656) (826,528) 1,872

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2018
Business Combinations [Abstract]
Schedule of Acquisition-Related Costs Included in General and Administrative Expenses	Acquisition-related costs accounted for as business combinations are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 $ 424 $ 998 $ 912 $ 3,796
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 after customary purchase price adjustments 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 Nine Months Ended September 30, 2017 Revenues $ 295,160 Net income (loss) 57,221 Earnings per share (basic and diluted) 0.47

Fair Value Measurements of Fi_2

Fair Value Measurements of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	Fair Value Measurements at September 30, 2018 Using Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 574 $ — $ 574 Liabilities: Commodity derivatives $ — $ 213,275 $ — $ 213,275 Fair Value Measurements at December 31, 2017 Using 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 Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts	The following derivative contracts were in place at September 30, 2018: Remainder 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 1,398,947 6,652,369 4,511,681 Weighted-average fixed price $ 52.33 $ 54.45 $ 53.49 Put options: Volume (Bbls) 989,379 1,749,757 — Weighted-average floor price $ 49.55 $ 53.83 $ — Weighted-average put premium $ (3.69) $ (5.43) $ — LLS basis swaps: Volume (Bbls) 1,711,789 — — Spread-WTI $ 3.02 $ — $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 2,184,376 6,425,146 4,846,020 Weighted-average fixed price $ 2.79 $ 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 September 30, December 31, September 30, December 31, Type Balance Sheet Location 2018 2017 2018 2017 Commodity contracts Short-term derivative instruments $ — $ 2,336 $ 131,539 $ 58,074 Netting arrangements Short-term derivative instruments — — — — Net recorded fair value $ — $ 2,336 $ 131,539 $ 58,074 Commodity contacts Long-term derivative instruments $ 574 $ 86 $ 81,736 $ 18,676 Netting arrangements Long-term derivative instruments — — — — Net recorded fair value $ 574 $ 86 $ 81,736 $ 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 three and nine months ending September 30, 2018 and 2017 (in thousands): Statements of For the Three Months Ended September 30, For the Nine Months Ended September 30, Operations Location 2018 2017 2018 2017 Commodity derivative contracts Gain (loss) on derivative instruments $ (76,358) $ (40,288) $ (227,533) $ 37,119

Accounts Receivable (Tables)

Accounts Receivable (Tables)	9 Months Ended
	Sep. 30, 2018
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following (in thousands): September 30, December 31, 2018 2017 Oil, gas and NGL sales $ 83,674 $ 67,584 Joint interest billings 18,129 9,467 Severance tax 304 171 North Louisiana Settlement receivable — 5,955 Environmental remediation 1,511 — Other current receivables 2,672 1,026 NLA Divestiture 5,264 — Allowance for doubtful accounts (200) (100) Total $ 111,354 $ 84,103
Schedule of Allowance for Doubtful Accounts Activity	The following table presents our allowance for doubtful accounts activity for the nine months ended September 30, 2018 (in thousands): Balance at beginning of period $ 100 Charged to costs and expenses 100 Balance at end of period $ 200

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Payables And Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consist of the following (in thousands): September 30, December 31, 2018 2017 Capital expenditures $ 121,123 $ 162,260 Preferred stock cash dividends 4,479 — Lease operating expense 5,410 5,796 General and administrative 9,150 1,642 Severance and ad valorem taxes 9,265 3,463 Interest expense 8,190 17,177 Derivative payable 11,919 5,281 Income taxes — 991 Other accrued liabilities 129 3,342 Total $ 169,665 $ 199,952

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 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 nine months ended September 30, 2018 (in thousands): Asset retirement obligations at beginning of period $ 14,557 Accretion expense 448 Liabilities incurred 611 Disposition of wells and gathering system (7,627) Asset retirement obligations at end of period 7,989 Less: current portion 90 Asset retirement obligations – long-term $ 7,899

Long Term Debt (Tables)

Long Term Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Our debt obligations consisted of the following at the dates indicated (in thousands): September 30, December 31, Debt Obligation 2018 2017 WRD revolving credit facility $ 399,000 $ 286,353 2025 Senior Notes (as defined below) (1) 700,000 500,000 Unamortized net discounts - 2025 Senior Notes (805) (4,914) Unamortized debt issuance costs - 2025 Senior Notes (12,198) (10,843) Total long-term debt $ 1,085,997 $ 770,596 (1) The estimated fair value of this fixed-rate debt was $722.8 million and $511.3 million at September 30, 2018 and December 31, 2017, respectively. The estimated fair values are based on quoted market prices and are 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): September 30, Credit Facility 2018 WRD revolving credit facility $ 1,050,000
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	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended September 30, For the Nine Months Ended September 30, Credit Facility 2018 2017 2018 2017 WRD revolving credit facility 4.12 % 3.71 % 4.02 % 3.63 %
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands): September 30, December 31, 2018 2017 WRD revolving credit facility Current $ 1,486 $ 1,203 Long-term 3,301 3,573 6.875% senior unsecured notes, due February 2025 12,198 10,843 Total $ 16,985 $ 15,619

Preferred Stock (Tables)

Preferred Stock (Tables)	9 Months Ended
	Sep. 30, 2018
Temporary Equity [Abstract]
Schedule of Preferred Stock	The following is a summary of the changes in our preferred stock for the nine months ended September 30, 2018: Series A Perpetual Convertible Preferred Stock (in thousands) Balance at December 31, 2017 $ 445,483 Accrual of paid-in-kind dividend 2,243 Beneficial conversion feature ("BCF") (1,872) Amortization of BCF 1,872 Balance at September 30, 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

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Summary of Changes in Common Shares Issued	Balance, December 31, 2017 101,137,277 Restricted common shares issued 1,076,165 Restricted common shares forfeited (60,911) Repurchase of vested restricted shares (1) (155,777) Balance, September 30, 2018 101,996,754 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Shareholders surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for employee tax obligations to the appropriate taxing authorities were approximately $4.2 million for the nine months ended September 30, 2018. The net-settlements had the effect of share repurchases by the Company as they reduced the number of shares that would have otherwise been outstanding due to the vesting and did not represent an expense to the Company.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Schedule of Calculation of Earnings (Loss) Per Share, or EPS	For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 Numerator: Net income (loss) available to WRD $ 11,523 $ (10,804) $ (118,345) $ 35,814 Less: Preferred stock dividends 6,756 6,450 22,106 6,523 Less: Undistributed earnings allocated to participating securities 1,233 — — 3,234 Net income (loss) available to common stockholders $ 3,534 $ (17,254) $ (140,451) $ 26,057 Denominator: Weighted-average common shares outstanding (in thousands) (1) (2) 99,639 99,142 99,433 95,369 Basic EPS $ 0.04 $ (0.17) $ (1.41) $ 0.27 Diluted EPS (1) (2) $ 0.04 $ (0.17) $ (1.41) $ 0.27 (1) The Company used the two-class method for both basic and diluted EPS. Restricted shares were excluded from the calculation of diluted EPS due to their antidilutive effect as we were in a loss position for the nine months ended September 30, 2018. For the three months ended September 30, 2018, 546 incremental restricted shares were excluded in the calculation of diluted EPS under the treasury stock method. For the three and nine months ended September 30, 2018, 32,402 shares and 32,349 shares, were excluded in 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 three months ended September 30, 2017, restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect as we were in a loss position. For the nine months ended September 30, 2017, 481 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the three and nine months ended September 30, 2017, 10,696 and 31,400 shares, respectively, were excluded in the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

Long Term Incentive Plans (Tabl

Long Term Incentive Plans (Tables)	9 Months Ended
	Sep. 30, 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 stock outstanding at December 31, 2017 1,897,790 $ 13.95 Granted (2) 1,076,165 $ 25.57 Forfeited (60,911) $ 16.03 Vested (561,581) $ 13.88 Restricted common stock outstanding at September 30, 2018 2,351,463 $ 19.23 (1) Determined by dividing the aggregate grant date fair value of stock subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common stock awards granted in 2018 was $27.5 million based on the grant date market price of ranging from $18.14 to $27.07 per share.

Segment Reporting (Tables)

Segment Reporting (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Reconciliation of Net Income (Loss) to Adjusted EBITDAX	The following table presents a reconciliation of Net income (loss) to Adjusted EBITDAX (in thousands): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 11,523 $ (10,804) $ (118,345) $ 35,814 Interest expense, net 15,718 8,749 43,027 20,953 Income tax (benefit) expense 19,055 (5,646) (28,394) 21,247 Depreciation, depletion and amortization 74,842 51,843 205,419 111,515 Exploration expense 13,814 4,749 19,891 17,868 Impairment of NLA Disposal Group — — 214,274 — (Gain) loss on derivative instruments 76,358 40,288 227,533 (37,119) Cash settlements received (paid) on derivative instruments (31,123) 5,802 (81,177) 6,895 Stock-based compensation 4,997 2,414 11,988 4,217 Incentive unit compensation — — 13,776 — Acquisition related costs 424 998 912 3,796 (Gain) loss on sale of properties 217 — (2,950) — Debt extinguishment costs — — — (11) Initial public offering costs — — — 182 Total Adjusted EBITDAX $ 185,825 $ 98,393 $ 505,954 $ 185,357

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Summary of Minimum Commitments of Lease Obligations	The table below reflects our estimated minimum commitments as of September 30, 2018 related to our office leases (in thousands): Remaining 2018 2019 2020 2021 2022 Thereafter Office Leases $ 390 $ 2,249 $ 2,285 $ 2,254 $ 2,066 $ 8,621

Organization and Basis of Pre_2

Organization and Basis of Presentation - Additional Information (Details) $ in Thousands	Jul. 27, 2018USD ($)	Jul. 31, 2018USD ($)	Sep. 30, 2018USD ($)subsidiary
Investment in unconsolidated affiliate
Cash capital contribution			$ 10,177
Minimum range of investment value the entity deems as more than minor			more than 3 to 5 percent
Income (Loss) from Equity Method Investments			$ (103)
Other income (expense)
Investment in unconsolidated affiliate
Income (Loss) from Equity Method Investments			(100)
Other
Investment in unconsolidated affiliate
Equity method investment			10,100
Irrevocable Standby Letter of Credit
Investment in unconsolidated affiliate
Letter of credit outstanding	$ 47,500		$ 47,500
Irrevocable Standby Letter of Credit | Port of Corpus Christi Authority
Investment in unconsolidated affiliate
Term of letter of credit	10 years
Esquisto II
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries | subsidiary			2
Joint Venture Partner | JWH
Investment in unconsolidated affiliate
Cash capital contribution		$ 10,200
Membership percentage		50.00%
JWH
Investment in unconsolidated affiliate
Number of leased acres for construction and operation of marine terminal facility		55
JWH | Port of Corpus Christi Authority
Investment in unconsolidated affiliate
Lease term		20 years
WHCC | JWH
Investment in unconsolidated affiliate
Membership percentage		50.00%
Membership interest subject to a call and put option		true
WHCC | JWH
Investment in unconsolidated affiliate
Rate of return to be included in determination of future potential membership sales price		3.00%
WHCC | JWH | JWH
Investment in unconsolidated affiliate
Cash capital contribution		$ 10,200

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Oil and Gas Properties (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Oil and gas properties
Capital costs excluded from depletion	$ 60.9

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 45,496	$ 13,465
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities	(45,838)	95,292
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions	$ (1,780)	$ 7,990

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Jan. 02, 2018	Jan. 01, 2018	Dec. 31, 2017
ASSETS
Oil and gas properties	$ 3,271,422	$ 2,995,687		$ 2,999,728
Accumulated depreciation, depletion and amortization	(426,373)	(367,874)		(368,245)
Other non-current assets	17,575	3,978		0
Liabilities:
Deferred tax liabilities	44,141	71,537		71,470
Stockholders' equity:
Accumulated earnings (deficit)	(118,605)	$ 26,016		$ 25,773
Contract with customers assets and liabilities
Contract assets	0
Contract liabilities	0
Adjustments for ASC 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	(5,913)		$ (4,041)
Accumulated depreciation, depletion and amortization	840		371
Other non-current assets	5,783		3,978
Liabilities:
Deferred tax liabilities	153		67
Stockholders' equity:
Accumulated earnings (deficit)	(864)		$ 243
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	3,277,335
Accumulated depreciation, depletion and amortization	(427,213)
Other non-current assets	11,792
Liabilities:
Deferred tax liabilities	43,988
Stockholders' equity:
Accumulated earnings (deficit)	$ (117,741)

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Consolidated Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Other income	$ 269			$ 308			$ 1,816	$ 1,244
Lease operating expenses	14,221			12,435			42,736	26,200
Gathering, processing and transportation	3,225			3,761			5,053	7,403
Depreciation, depletion and amortization	74,842			51,843			205,419	111,515
Other operating (income) expense	169			9			938	53
Income (loss) before income taxes	30,578			(16,450)			(146,739)	57,061
Income tax benefit (expense)	(19,055)			5,646			28,394	(21,247)
Net income (loss)	11,523	$ (14,094)	$ (115,774)	(10,804)	$ 26,366	$ 20,252	(118,345)	35,814
Oil sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	236,040			100,391			625,811	192,431
Natural gas sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	9,298			14,906			45,034	40,328
Natural gas liquid sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	13,883			$ 6,881			30,999	$ 12,948
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Other income	269						1,625
Lease operating expenses	14,681						43,736
Gathering, processing and transportation	6,246						14,366
Depreciation, depletion and amortization	75,023						205,889
Other operating (income) expense	1						460
Income (loss) before income taxes	30,422						(147,142)
Income tax benefit (expense)	(19,022)						28,481
Net income (loss)	11,400						(118,661)
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Oil sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	236,056						625,856
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Natural gas sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	10,378						48,353
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Natural gas liquid sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	16,125						37,727
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Other income							191
Lease operating expenses	(460)						(1,000)
Gathering, processing and transportation	(3,021)						(9,313)
Depreciation, depletion and amortization	(181)						(470)
Other operating (income) expense	168						478
Income (loss) before income taxes	156						403
Income tax benefit (expense)	(33)						(87)
Net income (loss)	123						316
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Oil sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(16)						(45)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(1,080)						(3,319)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas liquid sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	$ (2,242)						$ (6,728)

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Cash Flows (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Net income (loss)	$ (118,345)	$ 35,814
Depreciation, depletion and amortization	205,419	111,515
Deferred income tax expense (benefit)	(27,396)	20,263
Consideration paid to customers, net of amortization	(1,806)
Additions to oil and gas properties	(824,656)	$ (443,210)
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Net income (loss)	(118,661)
Depreciation, depletion and amortization	205,889
Deferred income tax expense (benefit)	(27,483)
Additions to oil and gas properties	(826,528)
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Net income (loss)	316
Depreciation, depletion and amortization	(470)
Deferred income tax expense (benefit)	87
Consideration paid to customers, net of amortization	(1,806)
Additions to oil and gas properties	$ 1,872

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Acquisition-Related Costs Included in General and Administrative Expenses (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Business Combinations [Abstract]
Acquisition-related costs	$ 424	$ 998	$ 912	$ 3,796

Acquisitions and Divestitures_2

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

Mar. 29, 2018USD ($)

Feb. 12, 2018USD ($)

Feb. 01, 2018USD ($)

Jan. 04, 2018USD ($)a

Jun. 30, 2017USD ($)shares

May 10, 2017

Oct. 31, 2018USD ($)

Sep. 30, 2018USD ($)

Jun. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Sep. 30, 2017USD ($)

Feb. 18, 2018USD ($)

Sep. 30, 2018USD ($)

Sep. 30, 2017USD ($)

Aug. 01, 2018USD ($)

Dec. 31, 2017USD ($)

Business Acquisitions

Acquisitions of oil and gas properties

$ 53,188

$ 549,033

Payments to acquire other property, plant and equipment

57,987

10,070

Capitalized assets

$ 79,120

79,120

$ 53,003

Unapplied construction deposits

1,714

Divestitures

Impairment of NLA Disposal Group

0

$ 214,300

$ 0

214,274

0

Pre-tax loss of NLA Disposal Group

202,200

6,800

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

Divestitures

Proceeds from divestiture

$ 206,400

Deposits received

$ 21,700

Preliminary purchase price adjustments - consents not obtained

900

Preliminary purchase price adjustments - net cash flows effective date to closing date

$ 9,700

Certain assets assigned after receipt of consent to assign

$ 900

Accrued divestiture contingent consideration receivable

400

$ 400

Period of time over which contingent payments will be determined

4 years

Payments received on contingent consideration arrangements

$ 400

Receivable for final settlement on sale of NLA Disposal Group

4,800

$ 4,800

Fee revenue from transitional accounting and land service provided

$ 900

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

Divestitures

Contingent consideration arrangement divestiture

35,000

35,000

NLA Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations | General and Administrative Expense

Divestitures

Gain on sale of NLA Disposal Group

3,000

Sand Mine

Business Acquisitions

Capitalized assets

44,500

44,500

Unapplied construction deposits

1,700

Eagle Ford Acquisitions [Member]

Business Acquisitions

Acquisitions of oil and gas properties

53,200

Capitalized transaction costs

$ 1,000

1,000

Purchase price allocated to unproved oil and natural gas properties

$ 48,200

APC/KKR Acquisitions

Business Acquisitions

Payment to acquire oil and natural gas properties prior to final purchase price settlement

$ 533,600

Payments to acquire oil and natural gas properties

$ 533,002

Business acquisition, date of acquisition agreement

May 10, 2017

Business acquisition, date of completion

Jun. 30, 2017

Business acquisition, post-closing receipt

$ 600

Business acquisition, aggregate purchase price, shares issued | shares

5.5

Burleson 2017 Acquisitions

Business Acquisitions

Payments to acquire oil and natural gas properties

19,300

Purchase price allocated to unproved oil and natural gas properties

$ 11,600

Burleson Sand | Sand Mine

Business Acquisitions

Surface and sand rights acquired | a

727

Payments to acquire other property, plant and equipment

$ 9,000

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Details) - APC/KKR Acquisitions - USD ($) $ in Thousands	8 Months Ended
	Feb. 18, 2018	Jun. 30, 2017
Business Acquisitions
Cash, Purchase price	$ 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

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Summary of Unaudited Pro Forma Financial Information (Details) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2017USD ($)$ / shares
Business Acquisition Pro Forma Information [Abstract]
Revenues	$ 295,160
Net income (loss)	$ 57,221
Earnings per share (basic and diluted) | $ / shares	$ 0.47

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	Sep. 30, 2018	Dec. 31, 2017
Assets:
Fair value of derivative asset	$ 574	$ 2,422
Liabilities:
Fair value of derivative liability	213,275	76,750
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	574	2,422
Liabilities:
Fair value of derivative liability	$ 213,275	$ 76,750

Fair Value Measurements of Fi_4

Fair Value Measurements of Financial Instruments - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
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	$ 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	$ 2.4	$ 3.2	$ 8.2	$ 13.9

Risk Management and Derivativ_3

Risk Management and Derivative Instruments - Additional Information (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative instruments designated as cash flow hedges	$ 0
Deferred premiums	6,100,000	$ 2,100,000
Derivative liabilities	212,700,000
Cash collateral received or pledged	$ 0

Risk Management and Derivativ_4

Risk Management and Derivative Instruments - Schedule of Derivative Contracts (Details)	9 Months Ended
	Sep. 30, 2018MMBTU$ / MMBTU$ / bblbbl
Crude Oil Derivative Contracts Fixed Price Swap Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	1,398,947
Weighted-average fixed price	52.33
Crude Oil Derivative Contracts Put Options Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	989,379
Weighted-average floor price	49.55
Weighted-average put premium	(3.69)
Crude Oil Derivative Contracts LLS Basis Swaps Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	1,711,789
Spread -WTI	3.02
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 LLS Basis Swaps 2019
Derivative [Line Items]
Volume (Bbls) | bbl	0
Spread -WTI	0
Crude Oil Derivative Contracts Fixed Price Swap 2020
Derivative [Line Items]
Volume (Bbls) | bbl	4,511,681
Weighted-average fixed price	53.49
Crude Oil Derivative Contracts Put Options 2020
Derivative [Line Items]
Volume (Bbls) | bbl	0
Weighted-average floor price	0
Weighted-average put premium	0
Crude Oil Derivative Contracts LLS Basis Swaps 2020
Derivative [Line Items]
Volume (Bbls) | bbl	0
Spread -WTI	0
Natural Gas Derivative Contracts Fixed Price Swap Remainder of 2018
Derivative [Line Items]
Volume (MMBtu) | MMBTU	2,184,376
Weighted-average fixed price | $ / MMBTU	2.79
Natural Gas Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (MMBtu) | MMBTU	6,425,146
Weighted-average fixed price | $ / MMBTU	2.79
Natural Gas Derivative Contracts Fixed Price Swap 2020
Derivative [Line Items]
Volume (MMBtu) | MMBTU	4,846,020
Weighted-average fixed price | $ / MMBTU	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	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Liability Derivatives, Net recorded fair value	$ 212,700
Short-term Derivative Instruments | Commodity Contract
Derivative [Line Items]
Asset Derivatives, Gross fair value	0	$ 2,336
Asset Derivatives, Netting arrangements	0	0
Asset Derivatives, Net recorded fair value	0	2,336
Liability Derivatives, Gross fair value	131,539	58,074
Liability Derivatives, Netting arrangements	0	0
Liability Derivatives, Net recorded fair value	131,539	58,074
Long-term Derivative Instruments | Commodity Contract
Derivative [Line Items]
Asset Derivatives, Gross fair value	574	86
Asset Derivatives, Netting arrangements	0	0
Asset Derivatives, Net recorded fair value	574	86
Liability Derivatives, Gross fair value	81,736	18,676
Liability Derivatives, Netting arrangements	0	0
Liability Derivatives, Net recorded fair value	$ 81,736	$ 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	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (76,358)	$ (40,288)	$ (227,533)	$ 37,119
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (76,358)	$ (40,288)	$ (227,533)	$ 37,119

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 83,674	$ 67,584
Joint interest billings	18,129	9,467
Severance tax	304	171
North Louisiana Settlement receivable		5,955
Environmental remediation	1,511
NLA Divestiture	5,264
Other current receivables	2,672	1,026
Allowance for doubtful accounts	(200)	(100)
Total	$ 111,354	$ 84,103

Accounts Receivable - Schedul_2

Accounts Receivable - Schedule of Accounts Notes Loans and Financing Receivable (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)
Accounts Notes Loans And Financing Receivable Gross Allowance And Net [Abstract]
Balance at beginning of period	$ 100
Charged to costs and expenses	100
Balance at end of period	$ 200

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Payables And Accruals [Abstract]
Capital expenditures	$ 121,123	$ 162,260
Preferred stock cash dividends	4,479
Lease operating expense	5,410	5,796
General and administrative	9,150	1,642
Severance and ad valorem taxes	9,265	3,463
Interest expense	8,190	17,177
Derivative payable	11,919	5,281
Income taxes		991
Other accrued liabilities	129	3,342
Total	$ 169,665	$ 199,952

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 14,557
Accretion expense	448
Liabilities incurred	611
Disposition of wells and gathering system	(7,627)
Asset retirement obligations at end of period	7,989
Less: current portion	90
Asset retirement obligations - long-term	$ 7,899	$ 14,467

Long Term Debt - Schedule of De

Long Term Debt - Schedule of Debt Obligations (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument
Unamortized debt issuance costs	$ (16,985)	$ (15,619)
Total long-term debt	1,085,997	770,596
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument
Long-term debt, gross	700,000	500,000
Unamortized discounts	(805)	(4,914)
Unamortized debt issuance costs	(12,198)	(10,843)
WRD Revolving Credit Facility
Debt Instrument
Long-term debt, gross	$ 399,000	$ 286,353

Long Term Debt - Schedule of _2

Long Term Debt - Schedule of Debt Obligations Additional Information (Details) - 6.875% Senior Unsecured Notes, Due February 2025 - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Debt Instrument
Debt instrument maturity period		Feb. 1, 2025
Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Debt Instrument
Estimated fair value of fixed rate debt	$ 722.8		$ 511.3
Registration Rights Exchange Offer
Debt Instrument
Debt instrument maturity period	Feb. 1, 2025

Long Term Debt - Schedule of Bo

Long Term Debt - Schedule of Borrowing Base Revolving Credit Facility (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Jul. 27, 2018	Mar. 23, 2018	Mar. 22, 2018
Line Of Credit Facility [Line Items]
WRD revolving credit facility	$ 1,050,000
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
WRD revolving credit facility	1,050,000		$ 1,050,000	$ 875,000
Irrevocable Standby Letter of Credit
Line Of Credit Facility [Line Items]
Letter of credit outstanding	$ 47,500	$ 47,500

Long Term Debt - Subsequent Eve

Long Term Debt - Subsequent Event (Details) - USD ($) $ in Thousands	Oct. 15, 2018	Sep. 30, 2018	Mar. 23, 2018	Mar. 22, 2018
Debt Instrument
Amount of borrowing base		$ 1,050,000
WRD Revolving Credit Facility
Debt Instrument
Amount of borrowing base		$ 1,050,000	$ 1,050,000	$ 875,000
Subsequent Event | WRD Revolving Credit Facility
Debt Instrument
Amount of borrowing base	$ 1,300,000
Decrease in pricing grid	0.25%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 90%
Debt Instrument
Commitment fee	0.50%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 90% | LIBOR
Debt Instrument
Variable margin rate	2.50%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 90% | Base Rate
Debt Instrument
Variable margin rate	1.50%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 75% but less than 90%
Debt Instrument
Commitment fee	0.50%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 75% but less than 90% | LIBOR
Debt Instrument
Variable margin rate	2.25%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 75% but less than 90% | Base Rate
Debt Instrument
Variable margin rate	1.25%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 50% but less than 75%
Debt Instrument
Commitment fee	0.50%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 50% but less than 75% | LIBOR
Debt Instrument
Variable margin rate	2.00%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 50% but less than 75% | Base Rate
Debt Instrument
Variable margin rate	1.00%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 25% but less than 50%
Debt Instrument
Commitment fee	0.375%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 25% but less than 50% | LIBOR
Debt Instrument
Variable margin rate	1.75%
Subsequent Event | WRD Revolving Credit Facility | Greater than or equal to 25% but less than 50% | Base Rate
Debt Instrument
Variable margin rate	0.75%
Subsequent Event | WRD Revolving Credit Facility | Less than 25%
Debt Instrument
Commitment fee	0.375%
Subsequent Event | WRD Revolving Credit Facility | Less than 25% | LIBOR
Debt Instrument
Variable margin rate	1.50%
Subsequent Event | WRD Revolving Credit Facility | Less than 25% | Base Rate
Debt Instrument
Variable margin rate	0.50%

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Details) - USD ($) $ in Thousands	Apr. 20, 2018	Sep. 19, 2017	Feb. 01, 2017	Sep. 30, 2018	Sep. 30, 2017	Mar. 23, 2018	Mar. 22, 2018	Nov. 20, 2017
Debt Instrument
Amount of borrowing base				$ 1,050,000
Proceeds from senior notes offering				$ 204,000	$ 494,744
6.875% Senior Unsecured Notes, Due February 2025
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.
6.875% Senior Unsecured Notes, Due February 2025 | Maximum
Debt Instrument
Debt instrument redemption percentage of principal amount				35.00%
6.875% Senior Unsecured Notes, Due February 2025 | Registration Rights Exchange Offer
Debt Instrument
Debt instrument interest rate percentage								6.875%
Debt instrument maturity date				Feb. 1, 2025
WRD Revolving Credit Facility
Debt Instrument
Amount of borrowing base				$ 1,050,000		$ 1,050,000	$ 875,000

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	4.12%	3.71%	4.02%	3.63%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument
Debt issuance costs	$ 3,301	$ 3,573
Unamortized deferred financing costs	16,985	15,619
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument
Unamortized deferred financing costs	12,198	10,843
WRD Revolving Credit Facility
Debt Instrument
Current	1,486	1,203
Debt issuance costs	$ 3,301	$ 3,573

Preferred Stock - Schedule of P

Preferred Stock - Schedule of Preferred Stock (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2018
Class Of Stock [Line Items]
Balance at December 31, 2017		$ 445,483			$ 445,483
Preferred stock paid-in-kind dividend		2,243	$ 6,450	$ 73
Beneficial conversion feature of preferred stock		(1,872)
Amortized beneficial conversion feature	$ 1,204	668
Balance at March 31, 2018					447,726
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock
Class Of Stock [Line Items]
Balance at December 31, 2017		$ 445,483			445,483
Preferred stock paid-in-kind dividend					2,243
Beneficial conversion feature of preferred stock					(1,872)
Amortized beneficial conversion feature					1,872
Balance at March 31, 2018					$ 447,726

Preferred Stock - Additional In

Preferred Stock - Additional Information (Details) - USD ($)	Oct. 31, 2018	Jul. 31, 2018	Apr. 30, 2018	Jan. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2018
Temporary Equity [Line Items]
Quarterly dividend announced date				Jan. 31, 2018
Amortized beneficial conversion feature					$ 1,204,000	$ 668,000
Preferred stock dividend paid							$ 13,512,000
Dividend, record date				Jan. 15, 2018
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity [Line Items]
Quarterly dividend, amount				$ 6,656,000
Beneficial conversion feature							$ 1,900,000
Redeemable Convertible Preferred Stock | Cash Dividend
Temporary Equity [Line Items]
Preferred stock dividend paid		$ 6.756	$ 6.756
Quarterly dividend, date paid		Jul. 31, 2018	Apr. 30, 2018
Dividend, record date		Jul. 15, 2018	Apr. 15, 2018
Redeemable Convertible Preferred Stock | Cash Dividend | Subsequent Event
Temporary Equity [Line Items]
Preferred stock dividend paid	$ 6.756
Quarterly dividend, date paid	Oct. 31, 2018
Dividend, record date	Oct. 15, 2018

Equity - Additional Information

Equity - Additional Information (Details) - $ / shares	Sep. 30, 2018	Dec. 31, 2017
Stockholders Equity Note [Abstract]
Common stock, shares authorized	500,000,000	500,000,000
Common stock, par value	$ 0.01	$ 0.01

Equity - Summary of Changes in

Equity - Summary of Changes in Common Shares Issued (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)shares
Stockholders Equity Note [Abstract]
Balance, Beginning of Period	101,137,277
Restricted common stock issued	1,076,165
Restricted common stock forfeited	(60,911)
Repurchase of vested restricted shares	(155,777)
Balance, End of Period	101,996,754
Payments Related To Tax Withholding For Share Based Compensation | $	$ 4,172

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						9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Numerator:
Net income (loss) available to WRD	$ 11,523	$ (14,094)	$ (115,774)	$ (10,804)	$ 26,366	$ 20,252	$ (118,345)	$ 35,814
Less: Preferred stock dividends	6,756			6,450			22,106	6,523
Less: Undistributed earnings allocated to participating securities	1,233			0			0	3,234
Net income (loss) available to common stockholders	$ 3,534			$ (17,254)			$ (140,451)	$ 26,057
Denominator:
Weighted-average common shares outstanding	99,639			99,142			99,433	95,369
Basic	$ 0.04			$ (0.17)			$ (1.41)	$ 0.27
Diluted	$ 0.04			$ (0.17)			$ (1.41)	$ 0.27

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	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares excluded in calculation of diluted EPS	32,402	10,696	32,349	31,400
Restricted Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares excluded in calculation of diluted EPS	546			481

Long Term Incentive Plans - Add

Long Term Incentive Plans - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost, weighted-average period			2 years 2 months 12 days
2016 Long-Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value			$ 27.5
Common stock authorized for issuance under plan	9,512,500		9,512,500
2016 Long-Term Incentive Plan | Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price			$ 25.57
Recognized compensation expense	$ 5	$ 2.4	$ 12	$ 4.2
Unrecognized compensation cost	$ 36.3		$ 36.3
2016 Long-Term Incentive Plan | Restricted Stock | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price			$ 18.14
2016 Long-Term Incentive Plan | Restricted Stock | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price			$ 27.07

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	9 Months Ended
	Sep. 30, 2018$ / sharesshares
Number of Shares
Restricted common shares outstanding, Beginning Balance | shares	1,897,790
Restricted commons shares, Granted | shares	1,076,165
Restricted commons shares, Forfeited | shares	(60,911)
Restricted commons shares, Vested | shares	(561,581)
Restricted common shares outstanding, Ending Balance | shares	2,351,463
Weighted Average Grant Date Fair Value per Share
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Beginning Balance | $ / shares	$ 13.95
Restricted common shares, Granted, Weighted-Average Grant Date Fair Value per Share | $ / shares	25.57
Restricted common shares, Forfeited, Weighted-Average Grant Date Fair Value per Share | $ / shares	16.03
Restricted common shares, Vested, Weighted-Average Grant Date Fair Value per Share | $ / shares	13.88
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Ending Balance | $ / shares	$ 19.23

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) $ in Thousands	May 14, 2018shares	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)item	Sep. 30, 2017USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive unit compensation expense | $		$ 0		$ 0	$ 13,776	$ 0
Contribution related to incentive unit compensation expense | $			$ 13,776
WildHorse Investment Holdings
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of tiers in distribution threshold | item					5
The LLCs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of tiers in distribution threshold | item					2
Esquisto Holdings | Incentive Award Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock distribution | shares	500,932

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Jun. 30, 2017
Carlyle Group, L.P. | NGP ECM
Related Party Transactions
Percentage of ownership interest in certain gross revenues			55.00%
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%
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%
Genesis Energy Partners, L.P
Related Party Transactions
Proceeds from sale of hydrocarbons and other liquids	$ 0	$ 500	$ 1,200	$ 1,900
Archrock Inc.
Related Party Transactions
Payments made to related party			100
NGP ECM | Director and Advisory Fees and Reimbursement of IPO Costs
Related Party Transactions
Payments made to related party	0		0
NGP ECM | Director and Advisory Fees and Reimbursement of IPO Costs | Maximum
Related Party Transactions
Related party payments (receipts), net		100		100
Cretic Energy Services, LLC | Drilling and Completion Activities
Related Party Transactions
Payments made to related party	0	100	0	200
CH4 Energy
Related Party Transactions
Payments made to related party		$ 100		500
CH4 Energy | Office Rental and Parking
Related Party Transactions
Payments made to related party				200
CH4 Energy | Office Rental and Parking | Maximum
Related Party Transactions
Payments made to related party	$ 100		$ 200
CH4 Energy | Landman Services and Expenses Incurred in 2016
Related Party Transactions
Payments made to related party				300
Service Providers
Related Party Transactions
Payments made to related party				$ 100
Affiliate of Carlyle Group
Related Party Transactions
Convertible preferred stock, shares issued					435,000

Segment Disclosures - Additiona

Segment Disclosures - Additional Information (Details) - segment	3 Months Ended	6 Months Ended
	Mar. 28, 2018	Sep. 30, 2018
Segment Reporting [Abstract]
Number of operating segments	2	1
Number of reportable segments	1	1

Segment Disclosures - Reconcili

Segment Disclosures - Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Details) - USD ($) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$ 11,523	$ (14,094)	$ (115,774)	$ (10,804)	$ 26,366	$ 20,252	$ (118,345)	$ 35,814
Interest expense, net	15,718			8,749			43,027	20,953
Income tax expense (benefit)	19,055			(5,646)			(28,394)	21,247
Depreciation, depletion and amortization	74,842			51,843			205,419	111,515
Exploration expense	13,814			4,749			19,891	17,868
Impairment of NLA Disposal Group	0		$ 214,300	0			214,274	0
(Gain) loss on derivative instruments	76,358			40,288			227,533	(37,119)
Cash settlements received (paid) on derivative instruments	(31,123)			5,802			(81,177)	6,895
Stock-based compensation	4,997			2,414			11,988	4,217
Incentive unit compensation expense	0			0			13,776	0
Acquisition-related costs	424			998			912	3,796
(Gain) loss on sale of properties	217			0			(2,950)	0
Debt extinguishment costs								(11)
Public offering costs								182
Total Adjusted EBITDAX	$ 185,825			$ 98,393			$ 505,954	$ 185,357

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Federal income tax refund	$ 2,300		$ 2,300
Income tax expense (benefit)	$ 19,055	$ (5,646)	$ (28,394)	$ 21,247
Effective tax rate	62.30%	34.30%	19.30%	37.20%
Statutory tax rate	21.00%	35.00%	21.00%	35.00%
Liability for unrecognized tax benefits	$ 0		$ 0

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Minimum Lease Obligation (Detail) - Office Lease [Member] $ in Thousands	Sep. 30, 2018USD ($)
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due remainder of 2018	$ 390
Operating Leases, Future Minimum Payments, Due 2019	2,249
Operating Leases, Future Minimum Payments, Due 2020	2,285
Operating Leases, Future Minimum Payments, Due 2021	2,254
Operating Leases, Future Minimum Payments, Due 2022	2,066
Operating Leases, Future Minimum Payments, Due thereafter	$ 8,621

Commitments and Contingencies_2

Commitments and Contingencies - Additional Information (Details) $ in Thousands	Aug. 02, 2018director	Sep. 30, 2018USD ($)leaseacre ft	Sep. 30, 2017USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)
Commitments And Contingencies [Line Items]
Number of leases executed | lease		2
Accrued liability for existing and potential claims				$ 0	$ 0
Environmental obligations recognized		$ 0			$ 0
Interruptible water availability agreement, start date		Feb. 1, 2017
Interruptible water availability agreement, end date		Dec. 31, 2021
Klein v. Graham, et al
Commitments And Contingencies [Line Items]
Number of directors named in legal action | director	7
Number of former directors named in a legal action | director	1
Interruptible Water Availability Agreement
Commitments And Contingencies [Line Items]
Aggregate of acre-feet of water per year | acre ft		6,978
Agreement payment		$ 500	$ 400

Subsequent Events (Details)

Subsequent Events (Details)	Oct. 30, 2018$ / shares	Sep. 30, 2018$ / shares	Dec. 31, 2017$ / shares
Subsequent Events
Common stock, par value		$ 0.01	$ 0.01
Subsequent Event | Chesapeake
Subsequent Events
Common stock, par value	$ 0.01
Subsequent Event | Chesapeake | Wildhorse Resource Development Corporation
Subsequent Events
Expected period during which proposed merger is expected to close	first half of 2019
Subsequent Event | Option One | Chesapeake | Wildhorse Resource Development Corporation
Subsequent Events
Common stock, exchange ratio	5.989
Subsequent Event | Option Two | Chesapeake | Wildhorse Resource Development Corporation
Subsequent Events
Common stock, exchange ratio	5.336
Cash per share	$ 3