Brazos Valley Longhorn, L.L.C. 10-Q 9 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
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		102,005,515

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 19,139	$ 226
Accounts receivable, net	109,017	84,103
Derivative instruments	0	2,336
Prepaid expenses and other current assets	4,669	3,290
Total current assets	132,825	89,955
Property and equipment:
Oil and gas properties	3,007,462	2,999,728
Other property and equipment	53,124	53,003
Accumulated depreciation, depletion and amortization	(351,248)	(368,245)
Total property and equipment, net	2,709,338	2,684,486
Other noncurrent assets:
Derivative instruments	491	86
Debt issuance costs	3,618	3,573
Other	13,256	0
Total assets	2,859,528	2,778,100
Current liabilities:
Accounts payable	65,710	53,005
Accrued liabilities	193,552	199,952
Derivative instruments	107,206	58,074
Total current liabilities	366,468	311,031
Noncurrent liabilities:
Long-term debt	935,609	770,596
Asset retirement obligations	7,518	14,467
Deferred tax liabilities	20,612	71,470
Derivative instruments	61,866	18,676
Other noncurrent liabilities	874	1,085
Total noncurrent liabilities	1,026,479	876,294
Total liabilities	1,392,947	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 June 30, 2018 and December 31, 2017, respectively, (involuntary liquidation preference of $450,389 and $448,146 at June 30, 2018 and December 31, 2017, respectively)	447,726	445,483
Stockholders' equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 102,007,516 shares and 101,137,277 shares issued and outstanding at June 30, 2018 and December 31, 2017, respectively	1,020	1,012
Additional paid-in capital	1,141,140	1,118,507
Accumulated earnings (deficit)	(123,305)	25,773
Total stockholders' equity	1,018,855	1,145,292
Total liabilities and equity	$ 2,859,528	$ 2,778,100

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 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	102,007,516	101,137,277
Common stock, shares outstanding	102,007,516	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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues and other income:
Other Income	$ 247	$ 529	$ 1,547	$ 936
Total operating revenues and other income	225,413	70,173	444,170	124,465
Operating expenses:
Lease operating expenses	12,088	6,837	28,515	13,765
Gathering, processing and transportation	476	1,942	1,828	3,642
Taxes other than income tax	12,779	4,509	24,560	8,408
Depreciation, depletion and amortization	70,694	33,229	130,577	59,672
Impairment of NLA Disposal Group (Note 3)	0	0	214,274	0
(Gain) loss on sale of properties	(3,167)	0	(3,167)	0
General and administrative expenses	12,917	10,049	25,644	17,531
Incentive unit compensation expense	13,776	0	13,776	0
Exploration expense	4,369	11,504	6,077	13,119
Other operating (income) expense	111	25	769	44
Total operating expense	124,043	68,095	442,853	116,181
Income (loss) from operations	101,370	2,078	1,317	8,284
Other income (expense):
Interest expense, net	(14,002)	(6,633)	(27,309)	(12,204)
Gain (loss) on derivative instruments	(110,805)	46,116	(151,175)	77,407
Other income (expense)	(13)	(2)	(150)	24
Total other income (expense)	(124,820)	39,481	(178,634)	65,227
Income (loss) before income taxes	(23,450)	41,559	(177,317)	73,511
Income tax benefit (expense)	9,356	(15,193)	47,449	(26,893)
Net income (loss) available to WRD	(14,094)	26,366	(129,868)	46,618
Preferred stock dividends	7,961	73	15,350	73
Undistributed earnings allocated to participating securities	0	387	0	434
Net income (loss) available to common stockholders	$ (22,055)	$ 25,906	$ (145,218)	$ 46,111
Earnings per common share:
Basic	$ (0.22)	$ 0.28	$ (1.46)	$ 0.49
Diluted	$ (0.22)	$ 0.28	$ (1.46)	$ 0.49
Weighted-average common shares outstanding:
Basic	99,411	93,685	99,328	93,452
Diluted	99,411	93,685	99,328	93,452
Oil sales
Revenues and other income:
Revenues	$ 207,392	$ 52,963	$ 389,771	$ 92,040
Natural gas sales
Revenues and other income:
Revenues	8,106	13,277	35,736	25,422
Natural gas liquid sales
Revenues and other income:
Revenues	$ 9,668	$ 3,404	$ 17,116	$ 6,067

UNAUDITED STATEMENTS OF CONDEN5

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities:
Net income (loss)	$ (129,868)	$ 46,618
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	130,249	59,367
Accretion of asset retirement obligations	328	305
Impairments of unproved properties	5,866	10,663
Impairment of NLA Disposal Group	214,274	0
Amortization of debt issuance cost	1,421	1,277
Accretion of senior note discount	105	105
(Gain) loss on derivative instruments	151,175	(77,407)
Cash settlements on derivative instruments	(50,054)	1,093
Deferred income tax expense (benefit)	(50,925)	26,893
Debt extinguishment benefit		(11)
Amortization of equity awards	6,991	1,803
Incentive unit compensation expense	13,776	0
(Gain) loss on sale of properties	(3,167)	0
Consideration paid to customers, net of amortization	(1,328)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	(18,321)	(22,307)
Decrease (increase) in prepaid expenses	(831)	(1,760)
Decrease (increase) in inventories	648
(Decrease) increase in accounts payable and accrued liabilities	21,168	25,395
Net cash flow provided by operating activities	291,507	72,034
Cash flows from investing activities:
Acquisitions of oil and gas properties	(19,914)	(547,389)
Additions to oil and gas properties	(578,669)	(211,263)
Additions to and acquisitions of other property and equipment	(25,010)	(6,189)
Construction deposits	(7,948)
Proceeds from NLA Divestiture	206,406
Net cash used in investing activities	(425,135)	(764,841)
Cash flows from financing activities:
Advances on revolving credit facilities	530,000	161,500
Payments on revolving credit facilities	(567,353)	(258,250)
Debt issuance cost	(3,246)	(10,756)
Proceeds from senior notes offering	204,000	347,354
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		(2,097)
Preferred stock dividends	(6,756)
Repurchase of vested restricted stock	(4,104)
Net cash provided by financing activities	152,541	704,191
Net change in cash, cash equivalents and restricted cash	18,913	11,384
Cash, cash equivalents and restricted cash, beginning of period	226	4,001
Cash, cash equivalents and restricted cash, end of period	$ 19,139	15,385
Convertible Preferred Stock
Cash flows from financing activities:
Cost incurred in conjunction with the issuance of stock		(2,416)
IPO
Cash flows from financing activities:
Cost incurred in conjunction with the issuance of stock		$ (601)

UNAUDITED CONDENSED CONSOLIDAT6

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Common Stock	Additional Paid in Capital	Accumulated Earnings (Deficit)	Total
Cumulative effect of accounting change (Note 2) | Restatement Adjustment | Accounting Standards Update 2014-09			$ 243	$ 243
Balance at Dec. 31, 2017	$ 1,012	$ 1,118,507	25,773	1,145,292
Net income (loss)			(129,868)	(129,868)
Preferred stock paid-in-kind dividend			(2,243)	(2,243)
Preferred stock cash dividend			(6,756)	(6,756)
Accrued preferred stock cash dividend			(4,479)	(4,479)
Beneficial conversion feature of preferred stock		1,872		1,872
Amortization of beneficial conversion feature			(1,872)	(1,872)
Repurchase of vested restricted common stock	(2)		(4,103)	(4,105)
Contribution related to incentive unit compensation expense		13,776		13,776
Amortization of equity awards	10	6,985		6,995
Balance at Jun. 30, 2018	$ 1,020	$ 1,141,140	$ (123,305)	$ 1,018,855

Organization and Basis of Prese

Organization and Basis of Presentation	6 Months Ended
	Jun. 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”) and Burleson Sand LLC (“Burleson Sand”) are wholly owned subsidiaries of the Company as of June 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. In June 2018, we formed a wholly-owned subsidiary, WHCC Infrastructure LLC, and in July 2018, made an initial capital contribution of approximately $10.0 million in such subsidiary for midstream opportunities. 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 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. Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 22,487 $ 306 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (23,993) 82,295 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (3,027) (8,687) 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, requiring leases to be classified as finance or operating leases. The classification will be 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. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize right-of-use assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. Originally, entities were the required to use the modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. However, in July 2018, the FASB issued targeted improvements to the new leasing standard, which now allows entities the option of recognizing the cumulative effect of applying the new standard as an adjustment to the opening balance of retained earnings in the year of adoption while continuing to present all prior periods under previous lease accounting guidance. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standard will extend over future periods. The Company is also currently evaluating which transition approach will be used upon adoption. 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. 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 June 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 June 30, 2018 For the Six Months Ended June 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 $ 207,392 $ 207,421 $ (29) $ 389,771 $ 389,800 $ (29) Natural gas sales 8,106 9,540 (1,434) 35,736 37,975 (2,239) NGL sales 9,668 12,193 (2,525) 17,116 21,601 (4,485) Other Income 247 304 (57) 1,547 1,738 (191) Operating expenses: Lease operating expenses 12,088 12,395 (307) 28,515 28,816 (301) Gathering, processing and transportation 476 4,022 (3,546) 1,828 8,120 (6,292) Depreciation, depletion and amortization 70,694 70,849 (155) 130,577 130,866 (289) Other operating (income) expense 111 282 (171) 769 1,080 (311) Income (loss) before income taxes (23,450) (23,583) 133 (177,317) (177,565) 248 Income tax benefit (expense) 9,356 9,383 (27) 47,449 47,503 (54) Net income (loss) (14,094) (14,200) 106 (129,868) (130,062) 194 At June 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,007,462 $ 3,012,871 $ (5,409) Accumulated depreciation, depletion and amortization (351,248) (351,907) 659 Other non-current assets 13,256 7,951 5,305 Liabilities: Deferred tax liabilities 20,612 20,492 120 Stockholders' Equity Accumulated earnings (deficit) (123,305) (122,629) (676) For the Six Months Ended June 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ (129,868) $ (130,062) $ 194 Depreciation, depletion and amortization 130,249 130,538 (289) Deferred income tax expense (benefit) (50,925) (50,979) 54 Consideration paid to customers, net of amortization (1,328) — (1,328) Cash flows from investing activities: Additions to oil and gas properties (578,669) (577,301) (1,368) 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	6 Months Ended
	Jun. 30, 2018
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Acquisition-related costs Acquisition-related costs for both related party and third party transactions 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 June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 $ 129 $ 2,199 $ 488 $ 2,798 2018 Acquisitions Lee County Acquisition. On March 1, 2018, we, through our wholly owned subsidiary, WHR EF, acquired certain acreage and associated production in Lee County, Texas for approximately $18.6 million from an undisclosed seller. This was accounted for as an asset acquisition since substantially all the fair value was concentrated in a group of similar assets. As such, an additional $0.4 million of acquisition costs were capitalized as part of the acquisition. We assigned $16.9 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 $25.1 million at June 30, 2018. In addition, we have $7.9 million of unapplied construction deposits that were paid during the six months ended June 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 six months ended June 30, 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 three and six months ended June 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 Three Months Ended For Six Months Ended June 30, June 30, 2017 2017 Revenues $ 93,471 $ 172,674 Net income (loss) 38,747 69,777 Earnings per share (basic and diluted) $ 0.41 $ 0.74 Burleson 2017 Acquisitions. During the six months ended June 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 $17.7 million, of which $10.6 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 includes 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. We have recorded this $0.9 million as a component of “Prepaid expenses and other current assets” on our Unaudited Condensed Consolidated Balance Sheets. In addition, WRD could receive contingent payments of up to $35.0 million, of which $0.4 million has been accrued, based on the number of wells spud on such properties over the next four years. Our contingent consideration arrangement meets the definition of a derivative, but qualifies for a scope exception. We have made an accounting policy election to record the contingent consideration when it is deemed to be realizable. 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 six months ended June 30, 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 six months ended June 30, 2018 and June 30, 2017 the NLA Disposal Group had a $201.8 million pre-tax loss and $0.6 million pre-tax profit, respectively. During the three and six months ended June 30, 2018, we recognized an estimated gain of $3.2 million which we expect to realize upon final settlement. We have recorded a $3.5 million final settlement receivable from Tanos at June 30, 2018. We recorded a $4.3 million receivable from Tanos related to the transition services agreement, which was collected on July 20, 2018. We provided Tanos with transitional accounting and land services during the three months ended June 30, 2018 and recognized $1.0 million of fees as a reduction to our general and administrative expenses.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	6 Months Ended
	Jun. 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 June 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 June 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 June 30, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Fair Value Measurements at June 30, 2018 Using Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 491 $ — $ 491 Liabilities: Commodity derivatives $ — $ 169,072 $ — $ 169,072 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 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 six months ended June 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 six months ended June 30, 2018, we recorded $4.4 million and $5.9 million of impairments of unproved properties, respectively. We recorded $10.0 million and $10.7 million of impairments of unproved properties for the three and six months ended June 30, 2017, respectively. · We recorded an impairment associated with the NLA Assets during the six months ended June 30, 2018. See Note 3—“Acquisitions and Divestitures—2018 Divestiture” for additional information.

Risk Management and Derivative

Risk Management and Derivative Instruments	6 Months Ended
	Jun. 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 six months ended June 30, 2018 and 2017 is net of deferred premiums of $4.2 million and $0.6 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 June 30, 2018 we had net derivative liabilities of $168.6 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 June 30, 2018: Remainder 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 2,958,527 6,652,369 4,511,681 Weighted-average fixed price $ 52.36 $ 54.45 $ 53.49 Put options: Volume (Bbls) 1,656,378 1,749,757 — Weighted-average floor price $ 50.04 $ 53.83 $ — Weighted-average put premium $ (3.64) $ (5.43) $ — LLS basis swaps: Volume (Bbls) 3,339,230 — — Spread-WTI $ 3.02 $ — $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 4,723,634 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 June 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 Type Balance Sheet Location June 30, 2018 December 31, 2017 June 30, 2018 December 31, 2017 Commodity contracts Short-term derivative instruments $ — $ 2,336 $ 107,206 $ 58,074 Netting arrangements Short-term derivative instruments — — — — Net recorded fair value $ — $ 2,336 $ 107,206 $ 58,074 Commodity contacts Long-term derivative instruments $ 491 $ 86 $ 61,866 $ 18,676 Netting arrangements Long-term derivative instruments — — — — Net recorded fair value $ 491 $ 86 $ 61,866 $ 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 six months ending June 30, 2018 and 2017 (in thousands): Statements of For the Three Months Ended June 30, For the Six Months Ended June 30, Operations Location 2018 2017 2018 2017 Commodity derivative contracts Gain (loss) on derivative instruments $ (110,805) $ 46,116 $ (151,175) $ 77,407

Accounts Receivable

Accounts Receivable	6 Months Ended
	Jun. 30, 2018
Receivables [Abstract]
Accounts Receivable	Note 6. Accounts Receivable Accounts receivable consist of the following (in thousands): June 30, December 31, 2018 2017 Oil, gas and NGL sales $ 77,866 $ 67,584 Joint interest billings 18,595 9,467 Severance tax 987 171 North Louisiana Settlement receivable — 5,955 Environmental remediation 1,258 — Other current receivables 2,627 1,026 NLA Divestiture and transition 7,884 — Allowance for doubtful accounts (200) (100) Total $ 109,017 $ 84,103 The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): June 30, December 31, 2018 2017 Balance at beginning of period $ 100 $ 100 Charged to costs and expenses 100 — Balance at end of period $ 200 $ 100

Accrued Liabilities

Accrued Liabilities	6 Months Ended
	Jun. 30, 2018
Payables And Accruals [Abstract]
Accrued Liabilities	Note 7. Accrued Liabilities Accrued liabilities consist of the following (in thousands): June 30, December 31, 2018 2017 Capital expenditures $ 136,615 $ 162,260 Preferred stock cash dividends 4,479 — Lease operating expense 4,708 5,796 General and administrative 6,243 1,642 Severance and ad valorem taxes 7,267 3,463 Interest expense 20,122 17,177 Derivative payable 10,804 5,281 Environmental liability 297 — Income taxes 2,166 991 Other accrued liabilities 851 3,342 Total $ 193,552 $ 199,952

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 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 six months ended June 30, 2018 (in thousands): Asset retirement obligations at beginning of period $ 14,557 Accretion expense 328 Liabilities incurred 350 Disposition of wells and gathering system (7,627) Asset retirement obligations at end of period 7,608 Less: current portion 90 Asset retirement obligations – long-term $ 7,518

Long Term Debt

Long Term Debt	6 Months Ended
	Jun. 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): June 30, December 31, Debt Obligation 2018 2017 WRD revolving credit facility $ 249,000 $ 286,353 2025 Senior Notes (as defined below) (1) 700,000 500,000 Unamortized net discounts - 2025 Senior Notes (809) (4,914) Unamortized debt issuance costs - 2025 Senior Notes (12,582) (10,843) Total long-term debt $ 935,609 $ 770,596 (1) The estimated fair value of this fixed-rate debt was $713.2 million and $511.3 million at June 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): June 30, Credit Facility 2018 WRD revolving credit facility $ 1,050,000 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. 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. In connection with the issuance and sale of the April Notes, the Company and the Guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with the Initial Purchaser, dated April 20, 2018. Pursuant to the Registration Rights Agreement, the Company and the Guarantors agreed to file a registration statement with the Securities and Exchange Commission so that holders of the April Notes can exchange the April Notes for registered notes that have substantially identical terms as the April Notes. In addition, the Company and the Guarantors have agreed to exchange the guarantees related to the April Notes for registered guarantees having substantially the same terms as the original guarantees. The Company and the Guarantors will use commercially reasonable efforts to cause the exchange to be consummated by April 20, 2019. 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 June 30, For the Six Months Ended June 30, Credit Facility 2018 2017 2018 2017 WRD revolving credit facility 3.84 % 3.40 % 3.97 % 3.48 % Unamortized Debt Issuance Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands): June 30, December 31, 2018 2017 WRD revolving credit facility Current $ 1,462 $ 1,203 Long-term 3,618 3,573 6.875% senior unsecured notes, due February 2025 12,582 10,843 Total $ 17,662 $ 15,619

Preferred Stock

Preferred Stock	6 Months Ended
	Jun. 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 three months ended June 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 June 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 will be amortized over the earliest preferred stock conversion period as additional dividends. At June 30, 2018, we have amortized $1.9 million of the BCF. On April 30, 2018, an aggregate quarterly cash dividend of $6.756 million was paid to holders of record as of April 15, 2018 for the period from February 1, 2018 to April 30, 2018. Subsequent Event. On July 31, 2018, an aggregate quarterly cash dividend of $6.756 million was paid to holders of record as of July 15, 2018 for the period from May 1, 2018 to July 31, 2018.

Equity

Equity	6 Months Ended
	Jun. 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 six months ended June 30, 2018: Balance, December 31, 2017 101,137,277 Restricted common shares issued 1,071,565 Restricted common shares forfeited (48,660) Repurchase of vested restricted shares (1) (152,666) Balance, June 30, 2018 102,007,516 (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 $4.1 million for the six months ended June 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 six months ended June 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	6 Months Ended
	Jun. 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 six months ended June 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 June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 Numerator: Net income (loss) available to WRD $ (14,094) $ 26,366 $ (129,868) $ 46,618 Less: Preferred stock dividends 7,961 73 15,350 73 Less: Undistributed earnings allocated to participating securities — 387 — 434 Net income (loss) available to common stockholders $ (22,055) $ 25,906 $ (145,218) $ 46,111 Denominator: Weighted-average common shares outstanding (in thousands) (1) 99,411 93,685 99,328 93,452 Basic EPS $ (0.22) $ 0.28 $ (1.46) $ 0.49 Diluted EPS (1) $ (0.22) $ 0.28 $ (1.46) $ 0.49 (1) The Company used the two-class method for both basic and diluted EPS. Restricted shares were excluded from the calculation of diluted EPS under the treasury stock method due to their antidilutive effect as we were in a loss position for the three and six months ended June 30, 2018. For the three and six months ended June 30, 2017, 455 incremental restricted shares and 308 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 six months ended June 30, 2018, 32,402 shares and 32,323 shares, were excluded in the calculation of diluted EPS due to their antidilutive effect under the if-converted method. For the three and six months ended June 30, 2017, 344 shares and 173 shares 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	6 Months Ended
	Jun. 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) 1,071,565 $ 25.58 Forfeited (48,660) $ 15.29 Vested (548,669) $ 13.95 Restricted common stock outstanding at June 30, 2018 2,372,026 $ 19.18 (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 $27.4 million based on the grant date market price of ranging from $18.14 to $27.07 per share. For the three months ended June 30, 2018 and 2017, we recorded $3.8 million and $1.3 million of recognized compensation expense, respectively, associated with these awards. For the six months ended June 30, 2018 and 2017, we recorded $7.0 million and $1.8 million of recognized compensation expense, respectively, associated with these awards. Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $41.4 million at June 30, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.39 years.

Incentive Units

Incentive Units	6 Months Ended
	Jun. 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 June 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).

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 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 and six months ended June 30, 2018 and 2017, we received $0.5 million, $1.2 million, $0.6 million and $1.5 million, respectively, from Genesis. Ms. Stephanie Hildebrandt has served as a member of our board of directors since December 2017. Ms. Hildebrandt has served as Senior Vice President, General Counsel, and Secretary of Archrock Inc., (“Archrock”) since August 2017. Archrock is a provider of compression services. During the three and six months ended June 30, 2018, we had disbursement of less than $0.1 million and $0.1 million, respectively, to Archrock. NGP Affiliated Companies Carlyle Group, L.P. The Carlyle Group, L.P. and certain of its affiliates indirectly own a 55% interest in certain gross revenues of NGP ECM, which is a limited partner entitled to 47.5% of the carried interest from NGP XI, and is entitled to 40% of the carried interest from NGP X US Holdings (without, in either case, any rights to vote or dispose of either such fund’s direct or indirect interest in us). NGP ECM manages investment funds, including NGP IX US Holdings, L.P. (“NGP IX US Holdings”), NGP X US Holdings and NGP XI, that collectively directly or indirectly through their equity interests in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings own a majority of our outstanding shares of common stock. 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 six months ended June 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 for the three and six months ended June 30, 2018. Cretic Energy Services, LLC . We recorded payments of $0.1 million for both the three and six months ended June 30, 2017 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 for the three and six months ended June 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 six months ended June 30, 2018 we had disbursements of less than $0.1 million and $0.1 million, respectively, to certain CH4 Energy entities for office rental and parking payments. During the three and six months ended June 30, 2017 we had disbursements of less than $0.1 million and $0.4 million to certain CH4 Energy entities, respectively. For the six months ended June 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 $0.1 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 six months ended June 30, 2017.

Segment Disclosures

Segment Disclosures	6 Months Ended
	Jun. 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 June 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 June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ (14,094) $ 26,366 $ (129,868) $ 46,618 Interest expense, net 14,002 6,633 27,309 12,204 Income tax (benefit) expense (9,356) 15,193 (47,449) 26,893 Depreciation, depletion and amortization 70,694 33,229 130,577 59,672 Exploration expense 4,369 11,504 6,077 13,119 Impairment of NLA Disposal Group — — 214,274 — (Gain) loss on derivative instruments 110,805 (46,116) 151,175 (77,407) Cash settlements received (paid) on derivative instruments (29,508) 2,076 (50,054) 1,093 Stock-based compensation 3,835 1,308 6,991 1,803 Incentive unit compensation 13,776 — 13,776 — Acquisition related costs 129 2,199 488 2,798 (Gain) loss on sale of properties (3,167) — (3,167) — Debt extinguishment costs — — — (11) Initial public offering costs — — — 182 Total Adjusted EBITDAX $ 161,485 $ 52,392 $ 320,129 $ 86,964

Income Taxes

Income Taxes	6 Months Ended
	Jun. 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. The Company recorded an income tax benefit of $9.4 million and an income tax expense of $15.2 million for the three months ended June 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 three months ended June 30, 2018 and 2017 was 39.9% and 36.6%, respectively. The increase in the effective tax rate was primarily due to state income taxes and incentive unit compensation, 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, and an excess tax benefit related to stock-based compensation recorded in the three months ended June 30, 2018. 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 and the impact of 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 recorded an income tax benefit of $47.5 million and an income tax expense of $26.9 million for the six months ended June 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 six months ended June 30, 2018 and 2017 was 26.8% and 36.6%, respectively. The decrease in the effective tax rate was primarily due to incentive unit compensation 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, state tax adjustments associated with the NLA Divestiture, and the impact of the state income tax provision. 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 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 June 30, 2018 and expects no significant change to the unrecognized tax benefits in the next twelve months.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 18. Commitments and Contingencies Lease Obligations We executed a new lease for corporate office space in June 2018 that has escalating payments starting, if certain conditions are satisfied, on October 1, 2018 through December 31, 2026. Assuming certain conditions are satisfied, the lease for our current corporate office will terminate on September 30, 2018. The table below reflects our estimated minimum commitments as of June 30, 2018 related to our corporate office leases (in thousands): Remaining 2018 2019 2020 2021 2022 Thereafter Office Lease $ 801 $ 1,958 $ 1,994 $ 2,036 $ 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 June 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. From time to time, we could be liable for environmental claims arising in the ordinary course of business. We recorded $0.3 million of environmental obligations at June 30, 2018 and did not record any environmental obligations 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 six months ended June 30, 2018 and 2017, respectively.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 19. Subsequent Events Quarterly Preferred Stock Dividend See Note 10—“Preferred Stock” for information regarding quarterly dividends paid on our outstanding preferred stock.

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 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.
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 22,487 $ 306 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (23,993) 82,295 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (3,027) (8,687)
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, requiring leases to be classified as finance or operating leases. The classification will be 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. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize right-of-use assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. Originally, entities were the required to use the modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. However, in July 2018, the FASB issued targeted improvements to the new leasing standard, which now allows entities the option of recognizing the cumulative effect of applying the new standard as an adjustment to the opening balance of retained earnings in the year of adoption while continuing to present all prior periods under previous lease accounting guidance. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standard will extend over future periods. The Company is also currently evaluating which transition approach will be used upon adoption. 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. 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 June 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 June 30, 2018 For the Six Months Ended June 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 $ 207,392 $ 207,421 $ (29) $ 389,771 $ 389,800 $ (29) Natural gas sales 8,106 9,540 (1,434) 35,736 37,975 (2,239) NGL sales 9,668 12,193 (2,525) 17,116 21,601 (4,485) Other Income 247 304 (57) 1,547 1,738 (191) Operating expenses: Lease operating expenses 12,088 12,395 (307) 28,515 28,816 (301) Gathering, processing and transportation 476 4,022 (3,546) 1,828 8,120 (6,292) Depreciation, depletion and amortization 70,694 70,849 (155) 130,577 130,866 (289) Other operating (income) expense 111 282 (171) 769 1,080 (311) Income (loss) before income taxes (23,450) (23,583) 133 (177,317) (177,565) 248 Income tax benefit (expense) 9,356 9,383 (27) 47,449 47,503 (54) Net income (loss) (14,094) (14,200) 106 (129,868) (130,062) 194 At June 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,007,462 $ 3,012,871 $ (5,409) Accumulated depreciation, depletion and amortization (351,248) (351,907) 659 Other non-current assets 13,256 7,951 5,305 Liabilities: Deferred tax liabilities 20,612 20,492 120 Stockholders' Equity Accumulated earnings (deficit) (123,305) (122,629) (676) For the Six Months Ended June 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ (129,868) $ (130,062) $ 194 Depreciation, depletion and amortization 130,249 130,538 (289) Deferred income tax expense (benefit) (50,925) (50,979) 54 Consideration paid to customers, net of amortization (1,328) — (1,328) Cash flows from investing activities: Additions to oil and gas properties (578,669) (577,301) (1,368) 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	We have made an accounting policy election to record the contingent consideration when it is deemed to be realizable.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 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 Six Months Ended June 30, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 22,487 $ 306 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (23,993) 82,295 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions (3,027) (8,687)
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 June 30, 2018 For the Six Months Ended June 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 $ 207,392 $ 207,421 $ (29) $ 389,771 $ 389,800 $ (29) Natural gas sales 8,106 9,540 (1,434) 35,736 37,975 (2,239) NGL sales 9,668 12,193 (2,525) 17,116 21,601 (4,485) Other Income 247 304 (57) 1,547 1,738 (191) Operating expenses: Lease operating expenses 12,088 12,395 (307) 28,515 28,816 (301) Gathering, processing and transportation 476 4,022 (3,546) 1,828 8,120 (6,292) Depreciation, depletion and amortization 70,694 70,849 (155) 130,577 131,866 (289) Other operating (income) expense 111 282 (171) 769 1,080 (311) Income (loss) before income taxes (23,450) (23,583) 133 (177,317) (177,565) 248 Income tax benefit (expense) 9,356 9,383 (27) 47,449 47,503 (54) Net income (loss) (14,094) (14,200) 106 (129,868) (130,062) 194 At June 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Assets: Oil and gas properties $ 3,007,462 $ 3,012,871 $ (5,409) Accumulated depreciation, depletion and amortization (351,248) (351,907) 659 Other non-current assets 13,256 7,951 5,305 Liabilities: Deferred tax liabilities 20,612 20,492 120 Stockholders' Equity Accumulated earnings (deficit) (123,305) (122,629) (676) For the Six Months Ended June 30, 2018 As Reported Without ASC 606 Increase/- Under ASC 606 Adoption Decrease Cash flows from operating activities: Net income $ (129,868) $ (130,062) $ 194 Depreciation, depletion and amortization 130,249 130,538 (289) Deferred income tax expense (benefit) (50,925) (50,979) 54 Consideration paid to customers, net of amortization (1,328) — (1,328) Cash flows from investing activities: Additions to oil and gas properties (578,669) (577,301) (1,368)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	6 Months Ended
	Jun. 30, 2018
Business Combinations [Abstract]
Schedule of Acquisition-Related Costs Included in General and Administrative Expenses	Acquisition-related costs for both related party and third party transactions 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 June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 $ 129 $ 2,199 $ 488 $ 2,798
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 Three Months Ended For Six Months Ended June 30, June 30, 2017 2017 Revenues $ 93,471 $ 172,674 Net income (loss) 38,747 69,777 Earnings per share (basic and diluted) $ 0.41 $ 0.74

Fair Value Measurements of Fi29

Fair Value Measurements of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Fair Value Measurements at June 30, 2018 Using Quoted Prices Significant Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 491 $ — $ 491 Liabilities: Commodity derivatives $ — $ 169,072 $ — $ 169,072 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 Derivativ30

Risk Management and Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts	The following derivative contracts were in place at June 30, 2018: Remainder 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 2,958,527 6,652,369 4,511,681 Weighted-average fixed price $ 52.36 $ 54.45 $ 53.49 Put options: Volume (Bbls) 1,656,378 1,749,757 — Weighted-average floor price $ 50.04 $ 53.83 $ — Weighted-average put premium $ (3.64) $ (5.43) $ — LLS basis swaps: Volume (Bbls) 3,339,230 — — Spread-WTI $ 3.02 $ — $ — Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 4,723,634 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 Type Balance Sheet Location June 30, 2018 December 31, 2017 June 30, 2018 December 31, 2017 Commodity contracts Short-term derivative instruments $ — $ 2,336 $ 107,206 $ 58,074 Netting arrangements Short-term derivative instruments — — — — Net recorded fair value $ — $ 2,336 $ 107,206 $ 58,074 Commodity contacts Long-term derivative instruments $ 491 $ 86 $ 61,866 $ 18,676 Netting arrangements Long-term derivative instruments — — — — Net recorded fair value $ 491 $ 86 $ 61,866 $ 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 six months ending June 30, 2018 and 2017 (in thousands): Statements of For the Three Months Ended June 30, For the Six Months Ended June 30, Operations Location 2018 2017 2018 2017 Commodity derivative contracts Gain (loss) on derivative instruments $ (110,805) $ 46,116 $ (151,175) $ 77,407

Accounts Receivable (Tables)

Accounts Receivable (Tables)	6 Months Ended
	Jun. 30, 2018
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following (in thousands): June 30, December 31, 2018 2017 Oil, gas and NGL sales $ 77,866 $ 67,584 Joint interest billings 18,595 9,467 Severance tax 987 171 North Louisiana Settlement receivable — 5,955 Environmental remediation 1,258 — Other current receivables 2,627 1,026 NLA Divestiture and transition 7,884 — Allowance for doubtful accounts (200) (100) Total $ 109,017 $ 84,103
Schedule of Allowance for Doubtful Accounts Activity	The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): June 30, December 31, 2018 2017 Balance at beginning of period $ 100 $ 100 Charged to costs and expenses 100 — Balance at end of period $ 200 $ 100

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	6 Months Ended
	Jun. 30, 2018
Payables And Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consist of the following (in thousands): June 30, December 31, 2018 2017 Capital expenditures $ 136,615 $ 162,260 Preferred stock cash dividends 4,479 — Lease operating expense 4,708 5,796 General and administrative 6,243 1,642 Severance and ad valorem taxes 7,267 3,463 Interest expense 20,122 17,177 Derivative payable 10,804 5,281 Environmental liability 297 — Income taxes 2,166 991 Other accrued liabilities 851 3,342 Total $ 193,552 $ 199,952

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 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 six months ended June 30, 2018 (in thousands): Asset retirement obligations at beginning of period $ 14,557 Accretion expense 328 Liabilities incurred 350 Disposition of wells and gathering system (7,627) Asset retirement obligations at end of period 7,608 Less: current portion 90 Asset retirement obligations – long-term $ 7,518

Long Term Debt (Tables)

Long Term Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Our debt obligations consisted of the following at the dates indicated (in thousands): June 30, December 31, Debt Obligation 2018 2017 WRD revolving credit facility $ 249,000 $ 286,353 2025 Senior Notes (as defined below) (1) 700,000 500,000 Unamortized net discounts - 2025 Senior Notes (809) (4,914) Unamortized debt issuance costs - 2025 Senior Notes (12,582) (10,843) Total long-term debt $ 935,609 $ 770,596 (1) The estimated fair value of this fixed-rate debt was $713.2 million and $511.3 million at June 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): June 30, Credit Facility 2018 WRD revolving credit facility $ 1,050,000
Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended June 30, For the Six Months Ended June 30, Credit Facility 2018 2017 2018 2017 WRD revolving credit facility 3.84 % 3.40 % 3.97 % 3.48 %
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): June 30, December 31, 2018 2017 WRD revolving credit facility Current $ 1,462 $ 1,203 Long-term 3,618 3,573 6.875% senior unsecured notes, due February 2025 12,582 10,843 Total $ 17,662 $ 15,619

Preferred Stock (Tables)

Preferred Stock (Tables)	6 Months Ended
	Jun. 30, 2018
Temporary Equity [Abstract]
Schedule of Preferred Stock	The following is a summary of the changes in our preferred stock for the three months ended June 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 June 30, 2018 $ 447,726

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Summary of Changes in Common Shares Issued	The following is a summary of the changes in our common stock issued for the six months ended June 30, 2018: Balance, December 31, 2017 101,137,277 Restricted common shares issued 1,071,565 Restricted common shares forfeited (48,660) Repurchase of vested restricted shares (1) (152,666) Balance, June 30, 2018 102,007,516 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 $4.1 million for the six months ended June 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)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Schedule of Calculation of Earnings (Loss) Per Share, or EPS	For the Three Months Ended June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 Numerator: Net income (loss) available to WRD $ (14,094) $ 26,366 $ (129,868) $ 46,618 Less: Preferred stock dividends 7,961 73 15,350 73 Less: Undistributed earnings allocated to participating securities — 387 — 434 Net income (loss) available to common stockholders $ (22,055) $ 25,906 $ (145,218) $ 46,111 Denominator: Weighted-average common shares outstanding (in thousands) (1) 99,411 93,685 99,328 93,452 Basic EPS $ (0.22) $ 0.28 $ (1.46) $ 0.49 Diluted EPS (1) $ (0.22) $ 0.28 $ (1.46) $ 0.49 The Company used the two-class method for both basic and diluted EPS. Restricted shares were excluded from the calculation of diluted EPS under the treasury stock method due to their antidilutive effect as we were in a loss position for the three and six months ended June 30, 2018. For the three and six months ended June 30, 2017, 455 incremental restricted shares and 308 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 six months ended June 30, 2018, 32,402 shares and 32,323 shares, were excluded in the calculation of diluted EPS due to their antidilutive effect under the if-converted method. For the three and six months ended June 30, 2017, 344 shares and 173 shares 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)	6 Months Ended
	Jun. 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) 1,071,565 $ 25.58 Forfeited (48,660) $ 15.29 Vested (548,669) $ 13.95 Restricted common stock outstanding at June 30, 2018 2,372,026 $ 19.18 (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 $27.4 million based on the grant date market price of ranging from $18.14 to $27.07 per share.

Segment Reporting (Tables)

Segment Reporting (Tables)	6 Months Ended
	Jun. 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 June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ (14,094) $ 26,366 $ (129,868) $ 46,618 Interest expense, net 14,002 6,633 27,309 12,204 Income tax (benefit) expense (9,356) 15,193 (47,449) 26,893 Depreciation, depletion and amortization 70,694 33,229 130,577 59,672 Exploration expense 4,369 11,504 6,077 13,119 Impairment of NLA Disposal Group — — 214,274 — (Gain) loss on derivative instruments 110,805 (46,116) 151,175 (77,407) Cash settlements received (paid) on derivative instruments (29,508) 2,076 (50,054) 1,093 Stock-based compensation 3,835 1,308 6,991 1,803 Incentive unit compensation 13,776 — 13,776 — Acquisition related costs 129 2,199 488 2,798 (Gain) loss on sale of properties (3,167) — (3,167) — Debt extinguishment costs — — — (11) Initial public offering costs — — — 182 Total Adjusted EBITDAX $ 161,485 $ 52,392 $ 320,129 $ 86,964

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Summary of Minimum Commitments of Lease Obligations	The table below reflects our estimated minimum commitments as of June 30, 2018 related to our corporate office leases (in thousands): Remaining 2018 2019 2020 2021 2022 Thereafter Office Lease $ 801 $ 1,958 $ 1,994 $ 2,036 $ 2,066 $ 8,621

Organization and Basis of Pre41

Organization and Basis of Presentation - Additional Information (Details) $ in Millions	1 Months Ended
	Jul. 31, 2018USD ($)	Jun. 30, 2018subsidiary
Esquisto II
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries | subsidiary		2
WHCC Infrastructure LLC
Organization And Basis Of Presentation [Line Items]
Capital contribution made to wholly owned subsidiary | $	$ 10

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Accounting Policies [Abstract]
Cash paid for interest, net of capitalized interest	$ 22,487	$ 306
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities	(23,993)	82,295
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions	$ (3,027)	$ (8,687)

Summary of Significant Accoun43

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Jan. 02, 2018	Jan. 01, 2018	Dec. 31, 2017
ASSETS
Oil and gas properties	$ 3,007,462	$ 2,995,687		$ 2,999,728
Accumulated depreciation, depletion and amortization	(351,248)	(367,874)		(368,245)
Other non-current assets	13,256	3,978		0
Liabilities:
Deferred tax liabilities	20,612	71,537		71,470
Stockholders' equity:
Accumulated earnings (deficit)	(123,305)	$ 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	(5,409)		$ (4,041)
Accumulated depreciation, depletion and amortization	659		371
Other non-current assets	5,305		3,978
Liabilities:
Deferred tax liabilities	120		67
Stockholders' equity:
Accumulated earnings (deficit)	(676)		$ 243
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	3,012,871
Accumulated depreciation, depletion and amortization	(351,907)
Other non-current assets	7,951
Liabilities:
Deferred tax liabilities	20,492
Stockholders' equity:
Accumulated earnings (deficit)	$ (122,629)

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Consolidated Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Other income	$ 247	$ 529	$ 1,547	$ 936
Lease operating expenses	12,088	6,837	28,515	13,765
Gathering, processing and transportation	476	1,942	1,828	3,642
Depreciation, depletion and amortization	70,694	33,229	130,577	59,672
Other operating (income) expense	111	25	769	44
Income (loss) before income taxes	(23,450)	41,559	(177,317)	73,511
Income tax benefit (expense)	9,356	(15,193)	47,449	(26,893)
Net income (loss)	(14,094)	26,366	(129,868)	46,618
Oil sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	207,392	52,963	389,771	92,040
Natural gas sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	8,106	13,277	35,736	25,422
Natural gas liquid sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	9,668	$ 3,404	17,116	$ 6,067
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	304		1,738
Lease operating expenses	12,395		28,816
Gathering, processing and transportation	4,022		8,120
Depreciation, depletion and amortization	70,849		130,866
Other operating (income) expense	282		1,080
Income (loss) before income taxes	(23,583)		(177,565)
Income tax benefit (expense)	9,383		47,503
Net income (loss)	(14,200)		(130,062)
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	207,421		389,800
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	9,540		37,975
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	12,193		21,601
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Other income	(57)		(191)
Lease operating expenses	(307)		(301)
Gathering, processing and transportation	(3,546)		(6,292)
Depreciation, depletion and amortization	(155)		(289)
Other operating (income) expense	(171)		(311)
Income (loss) before income taxes	133		248
Income tax benefit (expense)	(27)		(54)
Net income (loss)	106		194
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Oil sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(29)		(29)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(1,434)		(2,239)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas liquid sales
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	$ (2,525)		$ (4,485)

Summary of Significant Accoun45

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Cash Flows (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Net income (loss)	$ (129,868)	$ 46,618
Depreciation, depletion and amortization	130,249	59,367
Deferred income tax expense (benefit)	(50,925)	26,893
Consideration paid to customers, net of amortization	(1,328)
Additions to oil and gas properties	(578,669)	$ (211,263)
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)	(130,062)
Depreciation, depletion and amortization	130,538
Deferred income tax expense (benefit)	(50,979)
Additions to oil and gas properties	(577,301)
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Revenue Initial Application Period Cumulative Effect Transition [Line Items]
Net income (loss)	194
Depreciation, depletion and amortization	(289)
Deferred income tax expense (benefit)	54
Consideration paid to customers, net of amortization	(1,328)
Additions to oil and gas properties	$ (1,368)

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Acquisition-Related Costs Included in General and Administrative Expenses (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Business Combinations [Abstract]
Acquisition-related costs	$ 129	$ 2,199	$ 488	$ 2,798

Acquisitions and Divestitures47

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

Mar. 29, 2018USD ($)

Mar. 01, 2018USD ($)

Feb. 12, 2018USD ($)

Feb. 01, 2018USD ($)

Jan. 04, 2018USD ($)a

Jun. 30, 2017USD ($)shares

Jun. 30, 2018USD ($)

Jun. 30, 2017USD ($)

Jun. 30, 2018USD ($)

Jun. 30, 2017USD ($)

Feb. 18, 2018USD ($)

Dec. 31, 2017USD ($)

Business Acquisition [Line Items]

Payments to acquire other property, plant and equipment

$ 25,010

$ 6,189

Capitalized assets

$ 53,124

53,124

$ 53,003

Unapplied construction deposits

$ 7,948

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

Period of time over which contingent payments will be determined

4 years

Accrued divestiture contingent consideration receivable

400

$ 400

Impairment of NLA Disposal Group

0

$ 0

214,274

0

Pre-tax gain (loss) of NLA Disposal Group

(201,800)

600

Receivable for final settlement on sale of NLA Disposal Group

3,500

3,500

Receivable for transition services

4,300

4,300

Fee revenue from transitional accounting and land service provided

1,000

Maximum

Business Acquisition [Line Items]

Contingent consideration arrangement divestiture

35,000

35,000

General and Administrative Expense

Business Acquisition [Line Items]

Gain on sale of NLA Disposal Group

3,200

3,200

Prepaid Expenses And Other Current Assets

Business Acquisition [Line Items]

NLA Assets held for sale

900

900

Sand Mine

Business Acquisition [Line Items]

Capitalized assets

$ 25,100

$ 25,100

Producing and Non-producing properties in Lee County

Business Acquisition [Line Items]

Payments to acquire oil and natural gas properties

$ 18,600

Capitalized transaction costs

400

Purchase price allocated to unproved oil and natural gas properties

$ 16,900

APC/KKR Acquisitions

Business Acquisition [Line Items]

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 Acquisition [Line Items]

Payments to acquire oil and natural gas properties

17,700

Purchase price allocated to unproved oil and natural gas properties

$ 10,600

Burleson Sand | Sand Mine

Business Acquisition [Line Items]

Surface and sand rights acquired | a

727

Payments to acquire other property, plant and equipment

$ 9,000

Acquisitions and Divestitures48

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 Acquisition [Line Items]
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 Divestitures49

Acquisitions and Divestitures - Summary of Unaudited Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2017
Business Acquisition Pro Forma Information [Abstract]
Revenues	$ 93,471	$ 172,674
Net income (loss)	$ 38,747	$ 69,777
Earnings per share (basic and diluted)	$ 0.41	$ 0.74

Fair Value Measurements of Fi50

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	Jun. 30, 2018	Dec. 31, 2017
Assets:
Fair value of derivative asset	$ 491	$ 2,422
Liabilities:
Fair value of derivative liability	169,072	76,750
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	491	2,422
Liabilities:
Fair value of derivative liability	$ 169,072	$ 76,750

Fair Value Measurements of Fi51

Fair Value Measurements of Financial Instruments - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 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	$ 4.4	$ 10	$ 5.9	$ 10.7

Risk Management and Derivativ52

Risk Management and Derivative Instruments - Additional Information (Details)	3 Months Ended	6 Months Ended
	Jun. 30, 2018USD ($)	Jun. 30, 2018USD ($)
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative instruments designated as cash flow hedges	$ 0	$ 0
Deferred premiums	4,200,000	600,000
Derivative liabilities	168,600,000	168,600,000
Cash collateral received or pledged	$ 0	$ 0

Risk Management and Derivativ53

Risk Management and Derivative Instruments - Schedule of Derivative Contracts (Details)	6 Months Ended
	Jun. 30, 2018MMBTU$ / MMBTU$ / bblbbl
Crude Oil Derivative Contracts Fixed Price Swap Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	2,958,527
Weighted-average fixed price	52.36
Crude Oil Derivative Contracts Put Options Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	1,656,378
Weighted-average floor price	50.04
Weighted-average put premium	(3.64)
Crude Oil Derivative Contracts LLS Basis Swaps Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	3,339,230
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	4,723,634
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 Derivativ54

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	Jun. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Liability Derivatives, Net recorded fair value	$ 168,600
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	107,206	58,074
Liability Derivatives, Netting arrangements	0	0
Liability Derivatives, Net recorded fair value	107,206	58,074
Long-term Derivative Instruments | Commodity Contract
Derivative [Line Items]
Asset Derivatives, Gross fair value	491	86
Asset Derivatives, Netting arrangements	0	0
Asset Derivatives, Net recorded fair value	491	86
Liability Derivatives, Gross fair value	61,866	18,676
Liability Derivatives, Netting arrangements	0	0
Liability Derivatives, Net recorded fair value	$ 61,866	$ 18,676

Risk Management and Derivativ55

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (110,805)	$ 46,116	$ (151,175)	$ 77,407
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (110,805)	$ 46,116	$ (151,175)	$ 77,407

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 77,866	$ 67,584
Joint interest billings	18,595	9,467
Severance tax	987	171
North Louisiana Settlement receivable		5,955
Environmental remediation	1,258
NLA Divestiture and transition	7,884
Other current receivables	2,627	1,026
Allowance for doubtful accounts	(200)	(100)	$ (100)
Total	$ 109,017	$ 84,103

Accounts Receivable - Schedul57

Accounts Receivable - Schedule of Accounts Notes Loans and Financing Receivable (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Accounts Notes Loans And Financing Receivable Gross Allowance And Net [Abstract]
Balance at beginning of period	$ 100	$ 100
Charged to costs and expenses	100
Balance at end of period	$ 200	$ 100

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Payables And Accruals [Abstract]
Capital expenditures	$ 136,615	$ 162,260
Preferred stock cash dividends	4,479
Lease operating expense	4,708	5,796
General and administrative	6,243	1,642
Severance and ad valorem taxes	7,267	3,463
Interest expense	20,122	17,177
Derivative payable	10,804	5,281
Environmental liability	297
Income taxes	2,166	991
Other accrued liabilities	851	3,342
Total	$ 193,552	$ 199,952

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 14,557
Accretion expense	328	$ 305
Liabilities incurred	350
Disposition of wells and gathering system	(7,627)
Asset retirement obligations at end of period	7,608
Less: current portion	90
Asset retirement obligations - long-term	$ 7,518		$ 14,467

Long Term Debt - Schedule of De

Long Term Debt - Schedule of Debt Obligations (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (17,662)	$ (15,619)
Total long-term debt	935,609	770,596
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Long-term debt, gross	700,000	500,000
Unamortized discounts	(809)	(4,914)
Unamortized debt issuance costs	(12,582)	(10,843)
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	$ 249,000	$ 286,353

Long Term Debt - Schedule of 61

Long Term Debt - Schedule of Debt Obligations Additional Information (Details) - 6.875% Senior Unsecured Notes, Due February 2025 - USD ($) $ in Millions	6 Months Ended	9 Months Ended
	Jun. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Debt instrument maturity period		Feb. 1, 2025
Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Debt Instrument [Line Items]
Estimated fair value of fixed rate debt	$ 713.2		$ 511.3
Registration Rights Exchange Offer
Debt Instrument [Line Items]
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	Jun. 30, 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	$ 875,000

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Details) - USD ($) $ in Thousands	Apr. 20, 2018	Sep. 19, 2017	Feb. 01, 2017	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2017	Mar. 23, 2018	Mar. 22, 2018	Nov. 20, 2017
Debt Instrument [Line Items]
Amount of borrowing base				$ 1,050,000
Proceeds from senior notes offering				$ 204,000	$ 347,354
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
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 [Line Items]
Debt instrument redemption percentage of principal amount				35.00%
6.875% Senior Unsecured Notes, Due February 2025 | Registration Rights Exchange Offer
Debt Instrument [Line Items]
Debt instrument interest rate percentage									6.875%
Debt instrument maturity date				Feb. 1, 2025
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Amount of borrowing base							$ 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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	3.84%	3.40%	3.97%	3.48%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt issuance costs	$ 3,618	$ 3,573
Unamortized deferred financing costs	17,662	15,619
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Unamortized deferred financing costs	12,582	10,843
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Current	1,462	1,203
Debt issuance costs	$ 3,618	$ 3,573

Preferred Stock - Schedule of P

Preferred Stock - Schedule of Preferred Stock (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)
Class Of Stock [Line Items]
Balance at December 31, 2017	$ 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 Purchase Agreement | Redeemable Convertible Preferred Stock
Class Of Stock [Line Items]
Balance at December 31, 2017	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 ($) $ in Thousands	Jul. 31, 2018	Apr. 30, 2018	Jan. 31, 2018	Jun. 30, 2018
Temporary Equity [Line Items]
Quarterly dividend announced date			Jan. 31, 2018
Amortized beneficial conversion feature				$ 1,872
Preferred stock dividend paid				6,756
Dividend, record date			Jan. 15, 2018
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity [Line Items]
Quarterly dividend, amount			$ 6,656
Beneficial conversion feature				1,900
Amortized beneficial conversion feature				$ 1,900
Redeemable Convertible Preferred Stock | Cash Dividend
Temporary Equity [Line Items]
Preferred stock dividend paid		$ 6,756
Quarterly dividend, date paid		Apr. 30, 2018
Dividend, record date		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	Jul. 31, 2018
Dividend, record date	Jul. 15, 2018

Equity - Additional Information

Equity - Additional Information (Details) - $ / shares	Jun. 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 Millions	6 Months Ended
	Jun. 30, 2018USD ($)shares
Stockholders Equity Note [Abstract]
Balance, Beginning of Period	101,137,277
Restricted common stock issued	1,071,565
Restricted common stock forfeited	(48,660)
Repurchase of vested restricted shares	(152,666)
Balance, End of Period	102,007,516
Payments Related To Tax Withholding For Share Based Compensation | $	$ 4.1

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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Numerator:
Net income (loss) available to WRD	$ (14,094)	$ 26,366	$ (129,868)	$ 46,618
Less: Preferred stock dividends	7,961	73	15,350	73
Less: Undistributed earnings allocated to participating securities	0	387	0	434
Net income (loss) available to common stockholders	$ (22,055)	$ 25,906	$ (145,218)	$ 46,111
Denominator:
Weighted-average common shares outstanding	99,411	93,685	99,328	93,452
Basic	$ (0.22)	$ 0.28	$ (1.46)	$ 0.49
Diluted	$ (0.22)	$ 0.28	$ (1.46)	$ 0.49

Earnings Per Share - Schedule71

Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS Additional Information (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares excluded in calculation of diluted EPS	32,402	344	32,323	173
Restricted Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares excluded in calculation of diluted EPS		455		308

Long Term Incentive Plans - Add

Long Term Incentive Plans - Additional Information (Details) - 2016 Long-Term Incentive Plan - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value			$ 27.4
Common stock authorized for issuance under plan	9,512,500		9,512,500
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price			$ 25.58
Recognized compensation expense	$ 3.8	$ 1.3	$ 7	$ 1.8
Unrecognized compensation cost	$ 41.4		$ 41.4
Unrecognized compensation cost, weighted-average period			2 years 4 months 21 days
Restricted Stock | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price			$ 18.14
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	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Number of Shares
Restricted common shares outstanding, Beginning Balance | shares	1,897,790
Restricted commons shares, Granted | shares	1,071,565
Restricted commons shares, Forfeited | shares	(48,660)
Restricted commons shares, Vested | shares	(548,669)
Restricted common shares outstanding, Ending Balance | shares	2,372,026
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	25.58
Restricted common shares, Forfeited, Weighted-Average Grant Date Fair Value per Share | $ / shares	15.29
Restricted common shares, Vested, Weighted-Average Grant Date Fair Value per Share | $ / shares	13.95
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Ending Balance | $ / shares	$ 19.18

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) $ in Thousands	May 14, 2018shares	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)item	Jun. 30, 2017USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive unit compensation expense | $		$ 13,776	$ 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 Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Carlyle Group, L.P. | NGP ECM
Related Party Transaction [Line Items]
Percentage of ownership interest in certain gross revenues			55.00%
NGP ECM | NGP XI
Related Party Transaction [Line Items]
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds			47.50%
NGP ECM | NGP X US Holdings
Related Party Transaction [Line Items]
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds			40.00%
Genesis Energy Partners, L.P
Related Party Transaction [Line Items]
Proceeds from sale of hydrocarbons and other liquids	$ 0.5	$ 0.6	$ 1.2	$ 1.5
Archrock Inc. | Compression Services
Related Party Transaction [Line Items]
Payments made to related party	0.1		0.1
NGP ECM | Director and Advisory Fees and Reimbursement of IPO Costs
Related Party Transaction [Line Items]
Related party payments (receipts), net	0		0
NGP ECM | Director and Advisory Fees and Reimbursement of IPO Costs | Maximum
Related Party Transaction [Line Items]
Related party payments (receipts), net		0.1		0.1
Cretic Energy Services, LLC | Drilling and Completion Activities
Related Party Transaction [Line Items]
Payments made to related party	0	0.1	0	0.1
CH4 Energy | Maximum
Related Party Transaction [Line Items]
Payments made to related party		$ 0.1		0.4
CH4 Energy | Office Rental and Parking
Related Party Transaction [Line Items]
Payments made to related party				0.1
CH4 Energy | Office Rental and Parking | Maximum
Related Party Transaction [Line Items]
Payments made to related party	$ 0.1		$ 0.1
CH4 Energy | Landman Services and Expenses Incurred in 2016
Related Party Transaction [Line Items]
Payments made to related party				0.3
Service Providers
Related Party Transaction [Line Items]
Payments made to related party				$ 0.1
Affiliate of Carlyle Group [Member]
Related Party Transaction [Line Items]
Convertible preferred stock, shares issued		435,000		435,000

Segment Disclosures - Additiona

Segment Disclosures - Additional Information (Details) - segment	3 Months Ended
	Jun. 30, 2018	Mar. 28, 2018
Segment Reporting [Abstract]
Number of operating segments	1	2
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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$ (14,094)	$ 26,366	$ (129,868)	$ 46,618
Interest expense, net	14,002	6,633	27,309	12,204
Income tax (benefit) expense	(9,356)	15,193	(47,449)	26,893
Depreciation, depletion and amortization	70,694	33,229	130,577	59,672
Exploration expense	4,369	11,504	6,077	13,119
Impairment of NLA Disposal Group	0	0	214,274	0
(Gain) loss on derivative instruments	110,805	(46,116)	151,175	(77,407)
Cash settlements received (paid) on derivative instruments	(29,508)	2,076	(50,054)	1,093
Stock-based compensation	3,835	1,308	6,991	1,803
Incentive unit compensation expense	13,776	0	13,776	0
Acquisition-related costs	129	2,199	488	2,798
(Gain) loss on sale of properties	(3,167)	0	(3,167)	0
Debt extinguishment costs				(11)
Public offering costs				182
Total Adjusted EBITDAX	$ 161,485	$ 52,392	$ 320,129	$ 86,964

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	$ 9,356	$ (15,193)	$ 47,449	$ (26,893)
Effective tax rate	39.90%	36.60%	26.80%	36.60%
Effective income tax rate reconciliation, at federal statutory income tax rate, percent	21.00%	35.00%	21.00%	35.00%
Liability for unrecognized tax benefits	$ 0		$ 0
Significant change to unrecognized tax benefits in next twelve months	$ 0		$ 0

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Minimum Lease Obligation (Detail) - Office Lease [Member] $ in Thousands	Jun. 30, 2018USD ($)
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due remainder of 2018	$ 801
Operating Leases, Future Minimum Payments, Due 2019	1,958
Operating Leases, Future Minimum Payments, Due 2020	1,994
Operating Leases, Future Minimum Payments, Due 2021	2,036
Operating Leases, Future Minimum Payments, Due 2022	2,066
Operating Leases, Future Minimum Payments, Due thereafter	$ 8,621

Commitments and Contingencies80

Commitments and Contingencies - Additional Information (Details) $ in Thousands	Aug. 02, 2018director	Jun. 30, 2018USD ($)acre ft	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Commitments And Contingencies [Line Items]
Accrued liability for existing and potential claims		$ 0		$ 0
Environmental obligations recognized		$ 300		$ 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