Brazos Valley Longhorn, L.L.C. 10-Q/A 14 May 18 2018 Q1 Quarterly report (amended) Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Apr. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-Q/A
Amendment Flag	true
Amendment Description	On May 10, 2018, WildHorse Resource Development Corporation (the “Company”) filed with the Securities and Exchange Commission (the “SEC”) its Quarterly Report on Form 10-Q for the three months ended March 31, 2018 (the “Original Quarterly Report”). On the cover page of the Company’s Original Quarterly Report the Company inadvertently and incorrectly checked the box indicating that it was a “non-accelerated filer” as defined in Rule 12b-2 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The Company is filing this Amendment No. 1 (the “Amendment”) to correct the error on the cover page of the Original Quarterly Report to indicate that the Company is not a “non-accelerated filer” but is instead an “accelerated filer,” as defined in Rule 12b-2 of the Exchange Act. Except for the foregoing change to the cover page of the Original Quarterly Report, no other information included in the Original Quarterly Report is amended by this Amendment. This Amendment speaks as of the original filing date of the Original Quarterly Report and does not reflect events occurring after the filing date of the Original Quarterly Report, or modify or update the disclosures therein in any way other than as required to reflect the correction to the cover page of the Original Quarterly Report described herein.
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Trading Symbol	WRD
Entity Registrant Name	WildHorse Resource Development Corporation
Entity Central Index Key	1,681,714
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		101,277,876

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 7,017	$ 226
Accounts receivable, net	92,590	84,103
Derivative instruments	0	2,336
Prepaid expenses and other current assets	5,925	3,290
Total current assets	105,532	89,955
Property and equipment:
Oil and gas properties	2,734,096	2,999,728
Other property and equipment	33,647	53,003
Accumulated depreciation, depletion and amortization	(280,362)	(368,245)
Total property and equipment, net	2,487,381	2,684,486
Other noncurrent assets:
Derivative instruments	0	86
Debt issuance costs	3,875	3,573
Other	13,140	0
Total assets	2,609,928	2,778,100
Current liabilities:
Accounts payable	50,849	53,005
Accrued liabilities	159,476	199,952
Derivative instruments	67,478	58,074
Total current liabilities	277,803	311,031
Noncurrent liabilities:
Long-term debt	793,686	770,596
Asset retirement obligations	7,199	14,467
Deferred tax liabilities	33,412	71,470
Derivative instruments	22,999	18,676
Other noncurrent liabilities	980	1,085
Total noncurrent liabilities	858,276	876,294
Total liabilities	1,136,079	1,187,325
Commitments and contingencies (Note 18)	0	0
Preferred Stock, $0.01 par value: 50,000,000 shares authorized	0	0
Series A perpetual convertible preferred stock, $0.01 par value: 500,000 shares authorized; 435,000 shares issued and outstanding at March 31, 2018 and December 31, 2017, respectively, (involuntary liquidation preference of $450,389 and $448,146 at March 31, 2018 and December 31, 2017, respectively)	446,522	445,483
Stockholders’ equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 101,277,876 shares and 101,137,277 shares issued and outstanding at March 31, 2018 and December 31, 2017, respectively	1,013	1,012
Additional paid-in capital	1,123,534	1,118,507
Accumulated earnings (deficit)	(97,220)	25,773
Total stockholders’ equity	1,027,327	1,145,292
Total liabilities and equity	$ 2,609,928	$ 2,778,100

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	101,277,876	101,137,277
Common stock, shares outstanding	101,277,876	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
	Mar. 31, 2018	Mar. 31, 2017
Revenues and other income:
Oil sales	$ 182,379	$ 39,077
Natural gas sales	27,630	12,145
NGL sales	7,448	2,663
Other income	1,300	407
Total operating revenues and other income	218,757	54,292
Operating expenses:
Lease operating expenses	16,427	6,928
Gathering, processing and transportation	1,352	1,700
Taxes other than income tax	11,781	3,899
Depreciation, depletion and amortization	59,883	26,443
Impairment of NLA Disposal Group (Note 3)	214,274	0
General and administrative	12,727	7,482
Exploration expense	1,708	1,615
Other operating (income) expense	658	19
Total operating expense	318,810	48,086
Income (loss) from operations	(100,053)	6,206
Other income (expense):
Interest expense, net	(13,307)	(5,571)
Debt extinguishment costs	0	11
Gain (loss) on derivative instruments	(40,370)	31,291
Other income (expense)	(137)	15
Total other income (expense)	(53,814)	25,746
Income (loss) before income taxes	(153,867)	31,952
Income tax benefit (expense)	38,093	(11,700)
Net income (loss) available to WRD	(115,774)	20,252
Preferred stock dividends	7,389	0
Net income (loss) available to common stockholders	$ (123,163)	$ 20,252
Earnings per common share:
Basic	$ (1.24)	$ 0.22
Diluted	$ (1.24)	$ 0.22
Weighted-average common shares outstanding:
Basic	99,245	93,216
Diluted	99,245	93,216

UNAUDITED STATEMENTS OF CONDEN5

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ (115,774)	$ 20,252
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	59,670	26,293
Accretion of asset retirement obligations	213	150
Impairments of unproved properties	1,507	683
Impairment of NLA Disposal Group	214,274	0
Amortization of debt issuance cost	653	838
(Gain) loss on derivative instruments	40,370	(31,291)
Cash settlements on derivative instruments	(20,546)	(983)
Accretion of senior note discount	140	42
Deferred income tax expense (benefit)	(38,125)	11,700
Debt extinguishment benefit	0	(11)
Amortization of equity awards	3,156	495
Consideration paid to customers, net of amortization	(424)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	(13,595)	(8,047)
Decrease (increase) in prepaid expenses and other current assets	(368)	(735)
Decrease (increase) in inventories	169
(Decrease) increase in accounts payable and accrued liabilities	(13,351)	8,433
Net cash flow provided by operating activities	117,969	27,819
Cash flows from investing activities:
Acquisitions of oil and gas properties	(19,716)	(3,019)
Acquisition post-closing adjustment receipts		3,905
Additions to oil and gas properties	(297,939)	(63,344)
Additions to and acquisitions of other property and equipment	(12,896)	(1,521)
Construction deposits	(8,738)
Proceeds from NLA Divestiture	206,406
Acquisition deposits		(1,319)
Net cash used in investing activities	(132,883)	(65,298)
Cash flows from financing activities:
Advances on revolving credit facilities	308,000	15,500
Payments on revolving credit facilities	(285,353)	(258,250)
Debt issuance cost	(873)	(9,016)
Proceeds from senior notes offering		347,354
Proceeds from the issuance of common stock		34,457
Cost incurred in conjunction with the issuance of common stock		(2,473)
Repurchase of vested restricted stock	(69)
Net cash provided by financing activities	21,705	127,572
Net change in cash, cash equivalents and restricted cash	6,791	90,093
Cash, cash equivalents and restricted cash, beginning of period	226	4,001
Cash, cash equivalents and restricted cash, end of period	$ 7,017	$ 94,094

UNAUDITED CONDENSED CONSOLIDAT6

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid in Capital	Accumulated Earnings (Deficit)
Cumulative effect of accounting change (Note 2) | Restatement Adjustment | Accounting Standards Update 2014-09	$ 241			$ 241
Balance at Dec. 31, 2017	1,145,292	$ 1,012	$ 1,118,507	25,773
Net income (loss)	(115,774)			(115,774)
Preferred stock paid-in-kind dividend	(2,243)			(2,243)
Beneficial conversion feature of preferred stock	1,872		1,872
Amortization of beneficial conversion feature	(668)			(668)
Accrual of preferred stock cash dividend	(4,480)			(4,480)
Repurchase of vested restricted common stock	(69)			(69)
Amortization of equity awards	3,156	1	3,155
Balance at Mar. 31, 2018	$ 1,027,327	$ 1,013	$ 1,123,534	$ (97,220)

Organization and Basis of Prese

Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 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 March 31, 2018. WildHorse Resources Management Company, LLC (“WHRM”) is a wholly owned subsidiary of WHR II. Esquisto II has two wholly owned subsidiaries – Petromax E&P Burleson, LLC, and Burleson Water Resources, LLC (“Burleson Water”). WHRM is the named operator for all oil and natural gas properties owned by us. 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	3 Months Ended
	Mar. 31, 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 for our revenue recognition policy due to the adoption of the new revenue standard discussed below. Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Three Months Ended March 31, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 21,312 $ 656 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (34,893 ) 25,528 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions 4,229 — 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 either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the required modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standards will extend over future periods. 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 Previous periods have not been revised or adjusted and reflect the revenue standard in effect for those periods. Under the previous revenue recognition standard, ASC 605, 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 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) into our purchaser’s receiving equipment (typically a truck). 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 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 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 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 production is 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. 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 ’ Accumulated earnings (deficit) $ 25,773 $ 241 $ 26,014 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 March 31, 2018. Unsatisfied performance obligations - We have no unsatisfied performance obligations under our contracts. The majority of our contracts do not have stated volumes and we consider our performance obligations to be satisfied upon transfer of control of the commodity. In our remaining contracts where we are obligated to deliver a stated volume, all volumes are delivered in the period and we do not have any unsatisfied performance obligations under those contracts at the end of a period. Other Income - During the period, we owned the Oakfield gathering system, substantial fresh water supply and storage, a saltwater disposal well and several compressors. Though the Oakfield gathering system, saltwater disposal well and compressors were sold to Tanos Energy Holdings III, LLC (“Tanos”) as part of the NLA Divestiture (see Note 3), 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 March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Revenues: Oil sales $ 182,379 $ 182,379 $ — Natural gas sales 27,630 28,435 (805 ) NGL sales 7,448 9,413 (1,965 ) Other Income 1,300 1,166 134 Operating expenses: Lease operating expenses 16,427 16,433 (6 ) Gathering, processing and transportation 1,352 4,103 (2,751 ) Depreciation, depletion and amortization 59,883 60,016 (133 ) Other operating (income) expense 658 518 140 Income (loss) before income taxes (153,867 ) (153,981 ) 114 Income tax benefit (expense) 38,093 38,120 (27 ) Net income (loss) (115,774 ) (115,861 ) 87 At March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Assets: Oil and gas properties $ 2,734,096 $ 2,738,580 $ (4,484 ) Accumulated depreciation, depletion and amortization (280,362 ) (280,866 ) 504 Other non-current assets 13,140 8,737 4,403 Liabilities: Deferred tax liabilities 33,412 33,319 93 Stockholders' Equity Accumulated earnings (deficit) (97,220 ) (97,548 ) 328 For the Three Months Ended March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Cash flows from operating activities: Net income $ (115,774 ) $ (115,861 ) $ 87 Depreciation, depletion and amortization 59,670 59,803 (133 ) Deferred income tax expense (benefit) (38,125 ) (38,152 ) 27 Consideration paid to customers, net of amortization (424 ) — (424 ) Cash flows from investing activities: Additions to oil and gas properties (297,939 ) (298,382 ) 443 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	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 $ 359 $ 599 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. In addition, we paid construction deposits of approximately $8.7 million during the three months ended March 31, 2018 related to sand mine development. 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. We finalized our purchase price allocation during the three months ended March 31, 2018 and received a $0.6 million cash payment from the Sellers on February 1, 2018. Consideration consisted of 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. 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 months ended March 31, 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 the Three Months Ended March 31, 2017 (in thousands) Revenues $ 79,203 Net Income 30,139 Earnings per share (basic and diluted) $ 0.32 Burleson 2017 Acquisitions. We announced multiple transactions to acquire certain oil and natural gas producing and non-producing properties from third-parties in Burleson County, Texas. On February 2, 2017, we closed one transaction for approximately $2.4 million, subject to customary post-closing adjustments. We allocated $2.3 million of the purchase price to unproved oil and natural gas properties. Post-closing Receipt. During the three months ending March 31, 2017, we received a post-closing receipt of $3.9 million related to our December 19, 2016 Eagle Ford acquisition. 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 expect to obtain the necessary consent to assign approximately $0.9 million of NLA Assets held for Tanos within the next twelve months. 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 and 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 three months ended March 31, 2018 to adjust the carrying amount of the 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 three months ended March 31, 2018 and March 31, 2017 the NLA Disposal Group had a $204.8 million pre-tax loss and $1.1 million pre-tax profit, respectively.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). 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 March 31, 2018 and December 31, 2017. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. The fair market values of the derivative financial instruments reflected on the balance sheets as of March 31, 2018 and December 31, 2017 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Fair Value Measurements at March 31, 2018 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 1,284 $ — $ 1,284 Liabilities: Commodity derivatives $ — $ 91,760 $ — $ 91,760 Fair Value Measurements at December 31, 2017 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 2,422 $ — $ 2,422 Liabilities: Commodity derivatives $ — $ 76,750 $ — $ 76,750 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: • The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See “Note 8—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 months ended March 31, 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 months ended March 31, 2018 and 2017, we recorded $1.5 million and $0.7 million of impairments of unproved properties, respectively. • We recorded an impairment associated with the NLA Assets during the three months ended March 31, 2018. See Note 3—“Acquisitions and Divestitures—2018 Divestiture” for additional information.

Risk Management and Derivative

Risk Management and Derivative Instruments	3 Months Ended
	Mar. 31, 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, collars and deferred purchased puts to accomplish our hedging strategy. Through our basis swap instruments, we receive a fixed price differential and pay a variable price differential to the contract counterparty. Collars consist of a sold call and a purchased put that establish a ceiling and floor price for expected future oil and natural gas sales. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and where the Company agrees to defer the premium paid or received until the time of settlement. Cash received on settled derivative positions during the three months ended March 31, 2018 and 2017 is net of deferred premiums of $2.5 million and $0.1 million, respectively. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, all of which are also lenders under our credit agreement, which could expose us to credit risk in the event of default of our counterparties. We have master netting agreements for our derivative transactions with our counterparties and although we do not require collateral, we believe our counterparty risk is low because of the credit worthiness of our counterparties. Master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments by providing us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative or other financial instrument, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative and other financial asset receivables from the defaulting party. At March 31, 2018 we had net derivative liabilities of $90.5 million and 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 March 31, 2018: Remainder 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 4,764,565 6,652,369 1,101,762 Weighted-average fixed price $ 52.39 $ 54.45 $ 50.19 Collar contracts: Volume (Bbls) 12,208 — — Weighted-average floor price $ 50.00 $ — $ — Weighted-average ceiling price $ 62.10 $ — $ — Put options: Volume (Bbls) 2,118,859 1,749,757 — Weighted-average floor price $ 50.72 $ 53.83 $ — Weighted-average put premium $ (3.56 ) $ (5.43 ) $ — LLS basis swaps: Volume (Bbls) 2,804,384 — — Spread -WTI $ 3.05 $ — $ — 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 March 31, 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 March 31, December 31, March 31, December 31, Type Balance Sheet Location 2018 2017 2018 2017 Commodity contracts Short-term derivative instruments $ 1,004 $ 2,336 $ 68,481 $ 58,074 Netting arrangements Short-term derivative instruments (1,004 ) — (1,004 ) — Net recorded fair value $ — $ 2,336 $ 67,477 $ 58,074 Commodity contacts Long-term derivative instruments $ 280 $ 86 $ 23,279 $ 18,676 Netting arrangements Long-term derivative instruments (280 ) — (280 ) — Net recorded fair value $ — $ 86 $ 22,999 $ 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 months ending March 31, 2018 and 2017 (in thousands): Statements of For the Three Months Ended March 31, Operations Location 2018 2017 Commodity derivative contracts Gain (loss) on derivative instruments $ (40,370 ) $ 31,291

Accounts Receivable

Accounts Receivable	3 Months Ended
	Mar. 31, 2018
Receivables [Abstract]
Accounts Receivable	Note 6. Accounts Receivable Accounts receivable consist of the following (in thousands): March 31, December 31, 2018 2017 Oil, natural gas and NGL sales $ 72,872 $ 67,584 Joint interest billings 9,745 9,467 Severance tax 652 171 North Louisiana Settlement receivable (1) 5,291 5,955 Environmental remediation 1,261 — Other current receivables 2,969 1,026 Allowance for doubtful accounts (200 ) (100 ) Total $ 92,590 $ 84,103 (1) The North Louisiana Settlement receivable was subsequently collected in April 2018. The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): March 31, 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	3 Months Ended
	Mar. 31, 2018
Payables And Accruals [Abstract]
Accrued Liabilities	Note 7. Accrued Liabilities Accrued liabilities consist of the following (in thousands): March 31, December 31, 2018 2017 Capital expenditures $ 123,730 $ 162,260 Lease operating expense 5,536 5,796 General and administrative 4,793 1,642 Severance and ad valorem taxes 5,266 3,463 Interest expense 5,811 17,177 Derivative payable 7,612 5,281 Preferred stock cash dividends 4,480 — Environmental liability 1,451 — Income taxes — 991 Other accrued liabilities 797 3,342 Total $ 159,476 $ 199,952

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 (in thousands): Asset retirement obligations at beginning of period $ 14,557 Accretion expense 213 Liabilities incurred 146 Disposition of wells and gathering system (7,627 ) Asset retirement obligations at end of period 7,289 Less: current portion 90 Asset retirement obligations – long-term $ 7,199

Long Term Debt

Long Term Debt	3 Months Ended
	Mar. 31, 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): March 31, December 31, Credit Facility 2018 2017 WRD revolving credit facility $ 309,000 $ 286,353 2025 Senior Notes (as defined below) (1) 500,000 500,000 Unamortized discounts - 2025 Senior Notes (4,773 ) (4,914 ) Unamortized debt issuance costs - 2025 Senior Notes (10,541 ) (10,843 ) Total long-term debt $ 793,686 $ 770,596 (1) The estimated fair value of this fixed-rate debt was $501.3 million and $511.3 million at March 31, 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): March 31, 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. In addition, on September 19, 2017, we completed another private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par, which resulted in net proceeds of approximately $144.7 million. The notes issued in September 2017 are treated as a single class of debt securities with the 2025 Senior Notes issued in February 2017. The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year. The 2025 Senior Notes are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions). We have no material assets or operations that are independent of our existing subsidiaries. There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans. The net proceeds from each of the February 2017 and the September 2017 offerings of the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes. Pursuant to the registration rights agreements entered into in connection with the offerings of the 2025 Senior Notes, we agreed to file a registration statement with the 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. 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. Subsequent Event. On April 20, 2018, we completed another private placement of $200.0 million aggregate principal amount of our 2025 Senior Notes (the “April Notes”). The April 2018 issuance is treated as a single class of debt securities with the other outstanding 2025 Senior Notes. The April Notes were issued at a price of 102% of par. This issuance resulted in net proceeds of approximately $201.0 million, after deducting the initial purchaser’s discount and commissions and estimated offering expenses and excluding accrued interest. We used the net proceeds to repay borrowings outstanding under our revolving credit facility and for general corporate purposes. 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. 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 March 31, Credit Facility 2018 2017 WRD revolving credit facility 4.04 % 3.52 % Unamortized Debt Issuance Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands): March 31, December 31, 2018 2017 WRD revolving credit facility Current $ 1,423 $ 1,203 Long-term 3,875 3,573 6.875% senior unsecured notes, due February 2025 10,541 10,843 Total $ 15,839 $ 15,619

Preferred Stock

Preferred Stock	3 Months Ended
	Mar. 31, 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 March 31, 2018. Series A Perpetual Convertible Preferred Stock (in thousands) Balance at December 31, 2017 $ 445,483 Preferred stock paid-in-kind dividend 2,243 Unamortized beneficial conversion feature (1,204 ) Balance at March 31, 2018 $ 446,522 Preferred Stock Dividend 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 beneficial conversion feature that will be amortized over the earliest preferred stock conversion period as additional dividends. At March 31, 2018, we have amortized $0.7 million of the beneficial conversion feature. Subsequent Event. 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.

Equity

Equity	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Equity	Note 11. Equity Common Stock The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common stock issued for the three months ended March 31, 2018: Balance, December 31, 2017 101,137,277 Restricted common stock issued 178,612 Restricted common stock forfeited (34,407 ) Repurchase of vested restricted shares (3,606 ) Balance, March 31, 2018 101,277,876 See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted during the three months ended March 31, 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	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share	Note 12. Earnings Per Share The following sets forth the calculation of earnings (loss) per share, or EPS, for the three months ended March 31, 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 March 31, 2018 2017 Numerator: Net income (loss) available to WRD $ (115,774 ) $ 20,252 Less: Preferred stock dividends 7,389 — Net income (loss) available to common stockholders $ (123,163 ) $ 20,252 Denominator: Weighted-average common shares outstanding (in thousands) (1) 99,245 93,216 Basic EPS $ (1.24 ) $ 0.22 Diluted EPS (1) $ (1.24 ) $ 0.22 (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 months ended March 31, 2018. For the three months ended March 31, 2017, 6 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the three months ended March 31, 2018, 32,242 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	3 Months Ended
	Mar. 31, 2018
Long Term Incentive Plans
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: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common stock outstanding at December 31, 2017 1,897,790 $ 13.95 Granted (2) 178,612 $ 18.14 Forfeited (34,407 ) $ 13.94 Vested (20,541 ) $ 14.08 Restricted common stock outstanding at March 31, 2018 2,021,454 $ 14.32 (1) Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common stock awards granted in 2018 was $3.2 million based on the grant date market price of $18.14 per share. For the three months ended March 31, 2018 and 2017, we recorded $3.2 million and $0.5 million of recognized compensation expense, respectively, associated with these awards. Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $21.3 million at March 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.94 years.

Incentive Units

Incentive Units	3 Months Ended
	Mar. 31, 2018
Compensation Related Costs [Abstract]
Incentive Units	Note 14. Incentive Units Certain officers and employees have been granted awards of incentive units in WildHorse Investment Holdings, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The fair value of the incentive units will be remeasured on a quarterly basis until all payments have been made. Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. The payment likelihood related to these incentive units was not deemed probable at March 31, 2018. Vesting of all incentive units is generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested are forfeited if an employee is no longer employed. All incentive units will be forfeited if a holder resigns whether the incentive units are vested or not. If the payouts have not yet occurred, then all incentive units, whether or not vested, will be forfeited automatically (unless extended).

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Note 15. Related Party Transactions Board of Directors Relationships Mr. Grant E. Sims has served as a member of our board of directors since February 2017. Mr. Sims has served as a director and Chief Executive Officer of the general partner of Genesis Energy Partners, L.P. (“Genesis”) since August 2006 and Chairman of the board of directors of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the three months ended March 31, 2018 and 2017, we received $0.7 million and $0.9 million, respectively, from Genesis. 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 months ended March 31, 2017, we had net disbursements of $0.1 million related to expense reimbursements associated with their services as directors of WRD. We did not have any related party payments or receipts for the three months ended March 31, 2018. CH4 Energy. CH4 Energy entities are NGP affiliated companies and Mr. Brannon, one of our directors, is President of these entities. During the three months ended March 31, 2018 we had disbursements of $0.1 million to certain CH4 Energy entities for office rental and parking payments. During the three months ended March 31, 2017 we had disbursements of $0.4 million to certain CH4 Energy entities, of which $0.3 million was a reimbursement of landman services and expenses incurred in 2016 that CH4 Energy entities had paid on our behalf and $0.1 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 three months ended March 31, 2017.

Segment Disclosures

Segment Disclosures	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Segment Disclosures	Note 16. Segment Disclosures Our chief executive officer has been identified as our chief operating decision maker (“CODM”). As of March 31, 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 have 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 March 31, 2018 2017 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ (115,774 ) $ 20,252 Interest expense, net 13,307 5,571 Income tax (benefit) expense (38,093 ) 11,700 Depreciation, depletion and amortization 59,883 26,443 Exploration expense 1,708 1,615 Impairment of NLA Disposal Group 214,274 — (Gain) loss on derivative instruments 40,370 (31,291 ) Cash settlements received (paid) on derivative instruments (20,546 ) (983 ) Stock-based compensation 3,156 495 Acquisition related costs 359 599 Debt extinguishment costs — (11 ) Public offering costs — 182 Total Adjusted EBITDAX $ 158,644 $ 34,572

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 17. Income Taxes The Company is a corporation subject to federal and state income taxes. ncome tax benefit of $38.1 million and expense of $11.7 million for the three months ended March 31, 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 March 31, 2018 was 24.8%, compared to 36.6% for the three months ended March 31, 2017. The decrease of 11.8% in the effective tax rate was primarily due to a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation enacted in December 2017. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018, primarily due to the impact of the state income tax provision and state tax adjustments associated with the NLA Divestiture. 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 March 31, 2018 and expects no significant change to the unrecognized tax benefits in the next twelve months.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 18. Commitments and Contingencies Litigation & Environmental We are party to various ongoing and potential legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of March 31, 2018 and December 31, 2017. Our estimates are based on information known about the matters and the input of attorneys experienced in contesting, litigating, and settling similar matters. Actual amounts could differ from our estimates and other claims could be asserted. From time to time, we could be liable for environmental claims arising in the ordinary course of business. We recorded $1.5 million of environmental obligations at March 31, 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 during the three months ended March 31, 2018.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 19. Subsequent Events 2025 Senior Note Issuance See Note 9—“Long-term Debt” for information regarding the completion of another private placement of our 2025 Senior Notes. 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)	3 Months Ended
	Mar. 31, 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 Three Months Ended March 31, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 21,312 $ 656 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (34,893 ) 25,528 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions 4,229 —
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 either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the required modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standards will extend over future periods. 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 Previous periods have not been revised or adjusted and reflect the revenue standard in effect for those periods. Under the previous revenue recognition standard, ASC 605, 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 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) into our purchaser’s receiving equipment (typically a truck). 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 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 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 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 production is 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. 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 ’ Accumulated earnings (deficit) $ 25,773 $ 241 $ 26,014 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 March 31, 2018. Unsatisfied performance obligations - We have no unsatisfied performance obligations under our contracts. The majority of our contracts do not have stated volumes and we consider our performance obligations to be satisfied upon transfer of control of the commodity. In our remaining contracts where we are obligated to deliver a stated volume, all volumes are delivered in the period and we do not have any unsatisfied performance obligations under those contracts at the end of a period. Other Income - During the period, we owned the Oakfield gathering system, substantial fresh water supply and storage, a saltwater disposal well and several compressors. Though the Oakfield gathering system, saltwater disposal well and compressors were sold to Tanos Energy Holdings III, LLC (“Tanos”) as part of the NLA Divestiture (see Note 3), 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 March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Revenues: Oil sales $ 182,379 $ 182,379 $ — Natural gas sales 27,630 28,435 (805 ) NGL sales 7,448 9,413 (1,965 ) Other Income 1,300 1,166 134 Operating expenses: Lease operating expenses 16,427 16,433 (6 ) Gathering, processing and transportation 1,352 4,103 (2,751 ) Depreciation, depletion and amortization 59,883 60,016 (133 ) Other operating (income) expense 658 518 140 Income (loss) before income taxes (153,867 ) (153,981 ) 114 Income tax benefit (expense) 38,093 38,120 (27 ) Net income (loss) (115,774 ) (115,861 ) 87 At March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Assets: Oil and gas properties $ 2,734,096 $ 2,738,580 $ (4,484 ) Accumulated depreciation, depletion and amortization (280,362 ) (280,866 ) 504 Other non-current assets 13,140 8,737 4,403 Liabilities: Deferred tax liabilities 33,412 33,319 93 Stockholders' Equity Accumulated earnings (deficit) (97,220 ) (97,548 ) 328 For the Three Months Ended March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Cash flows from operating activities: Net income $ (115,774 ) $ (115,861 ) $ 87 Depreciation, depletion and amortization 59,670 59,803 (133 ) Deferred income tax expense (benefit) (38,125 ) (38,152 ) 27 Consideration paid to customers, net of amortization (424 ) — (424 ) Cash flows from investing activities: Additions to oil and gas properties (297,939 ) (298,382 ) 443 Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on our consolidated financial statements and footnote disclosures.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 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 Three Months Ended March 31, 2018 2017 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 21,312 $ 656 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities (34,893 ) 25,528 (Increase) decrease in accounts receivable related to capital expenditures and acquisitions 4,229 —
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): 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 ’ Accumulated earnings (deficit) $ 25,773 $ 241 $ 26,014 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 March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Revenues: Oil sales $ 182,379 $ 182,379 $ — Natural gas sales 27,630 28,435 (805 ) NGL sales 7,448 9,413 (1,965 ) Other Income 1,300 1,166 134 Operating expenses: Lease operating expenses 16,427 16,433 (6 ) Gathering, processing and transportation 1,352 4,103 (2,751 ) Depreciation, depletion and amortization 59,883 60,016 (133 ) Other operating (income) expense 658 518 140 Income (loss) before income taxes (153,867 ) (153,981 ) 114 Income tax benefit (expense) 38,093 38,120 (27 ) Net income (loss) (115,774 ) (115,861 ) 87 At March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Assets: Oil and gas properties $ 2,734,096 $ 2,738,580 $ (4,484 ) Accumulated depreciation, depletion and amortization (280,362 ) (280,866 ) 504 Other non-current assets 13,140 8,737 4,403 Liabilities: Deferred tax liabilities 33,412 33,319 93 Stockholders' Equity Accumulated earnings (deficit) (97,220 ) (97,548 ) 328 For the Three Months Ended March 31, 2018 As Reported Under ASC 606 Without ASC 606 Adoption Increase/(Decrease) Cash flows from operating activities: Net income $ (115,774 ) $ (115,861 ) $ 87 Depreciation, depletion and amortization 59,670 59,803 (133 ) Deferred income tax expense (benefit) (38,125 ) (38,152 ) 27 Consideration paid to customers, net of amortization (424 ) — (424 ) Cash flows from investing activities: Additions to oil and gas properties (297,939 ) (298,382 ) 443

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 $ 359 $ 599
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	The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 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 the Three Months Ended March 31, 2017 (in thousands) Revenues $ 79,203 Net Income 30,139 Earnings per share (basic and diluted) $ 0.32

Fair Value Measurements of Fi29

Fair Value Measurements of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Fair Value Measurements at March 31, 2018 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 1,284 $ — $ 1,284 Liabilities: Commodity derivatives $ — $ 91,760 $ — $ 91,760 Fair Value Measurements at December 31, 2017 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 2,422 $ — $ 2,422 Liabilities: Commodity derivatives $ — $ 76,750 $ — $ 76,750

Risk Management and Derivativ30

Risk Management and Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts	The following derivative contracts were in place at March 31, 2018: Remainder 2018 2019 2020 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 4,764,565 6,652,369 1,101,762 Weighted-average fixed price $ 52.39 $ 54.45 $ 50.19 Collar contracts: Volume (Bbls) 12,208 — — Weighted-average floor price $ 50.00 $ — $ — Weighted-average ceiling price $ 62.10 $ — $ — Put options: Volume (Bbls) 2,118,859 1,749,757 — Weighted-average floor price $ 50.72 $ 53.83 $ — Weighted-average put premium $ (3.56 ) $ (5.43 ) $ — LLS basis swaps: Volume (Bbls) 2,804,384 — — Spread -WTI $ 3.05 $ — $ —
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 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 March 31, December 31, March 31, December 31, Type Balance Sheet Location 2018 2017 2018 2017 Commodity contracts Short-term derivative instruments $ 1,004 $ 2,336 $ 68,481 $ 58,074 Netting arrangements Short-term derivative instruments (1,004 ) — (1,004 ) — Net recorded fair value $ — $ 2,336 $ 67,477 $ 58,074 Commodity contacts Long-term derivative instruments $ 280 $ 86 $ 23,279 $ 18,676 Netting arrangements Long-term derivative instruments (280 ) — (280 ) — Net recorded fair value $ — $ 86 $ 22,999 $ 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 months ending March 31, 2018 and 2017 (in thousands): Statements of For the Three Months Ended March 31, Operations Location 2018 2017 Commodity derivative contracts Gain (loss) on derivative instruments $ (40,370 ) $ 31,291

Accounts Receivable (Tables)

Accounts Receivable (Tables)	3 Months Ended
	Mar. 31, 2018
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following (in thousands): March 31, December 31, 2018 2017 Oil, natural gas and NGL sales $ 72,872 $ 67,584 Joint interest billings 9,745 9,467 Severance tax 652 171 North Louisiana Settlement receivable (1) 5,291 5,955 Environmental remediation 1,261 — Other current receivables 2,969 1,026 Allowance for doubtful accounts (200 ) (100 ) Total $ 92,590 $ 84,103 (1) The North Louisiana Settlement receivable was subsequently collected in April 2018.
Schedule of Allowance for Doubtful Accounts Activity	The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands): March 31, 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)	3 Months Ended
	Mar. 31, 2018
Payables And Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consist of the following (in thousands): March 31, December 31, 2018 2017 Capital expenditures $ 123,730 $ 162,260 Lease operating expense 5,536 5,796 General and administrative 4,793 1,642 Severance and ad valorem taxes 5,266 3,463 Interest expense 5,811 17,177 Derivative payable 7,612 5,281 Preferred stock cash dividends 4,480 — Environmental liability 1,451 — Income taxes — 991 Other accrued liabilities 797 3,342 Total $ 159,476 $ 199,952

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2018 (in thousands): Asset retirement obligations at beginning of period $ 14,557 Accretion expense 213 Liabilities incurred 146 Disposition of wells and gathering system (7,627 ) Asset retirement obligations at end of period 7,289 Less: current portion 90 Asset retirement obligations – long-term $ 7,199

Long Term Debt (Tables)

Long Term Debt (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Our debt obligations consisted of the following at the dates indicated (in thousands): March 31, December 31, Credit Facility 2018 2017 WRD revolving credit facility $ 309,000 $ 286,353 2025 Senior Notes (as defined below) (1) 500,000 500,000 Unamortized discounts - 2025 Senior Notes (4,773 ) (4,914 ) Unamortized debt issuance costs - 2025 Senior Notes (10,541 ) (10,843 ) Total long-term debt $ 793,686 $ 770,596 (1) The estimated fair value of this fixed-rate debt was $501.3 million and $511.3 million at March 31, 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): March 31, 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 March 31, Credit Facility 2018 2017 WRD revolving credit facility 4.04 % 3.52 %
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): March 31, December 31, 2018 2017 WRD revolving credit facility Current $ 1,423 $ 1,203 Long-term 3,875 3,573 6.875% senior unsecured notes, due February 2025 10,541 10,843 Total $ 15,839 $ 15,619

Preferred Stock (Tables)

Preferred Stock (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018. Series A Perpetual Convertible Preferred Stock (in thousands) Balance at December 31, 2017 $ 445,483 Preferred stock paid-in-kind dividend 2,243 Unamortized beneficial conversion feature (1,204 ) Balance at March 31, 2018 $ 446,522

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018: Balance, December 31, 2017 101,137,277 Restricted common stock issued 178,612 Restricted common stock forfeited (34,407 ) Repurchase of vested restricted shares (3,606 ) Balance, March 31, 2018 101,277,876

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Schedule of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of earnings (loss) per share, or EPS, for the three months ended March 31, 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 March 31, 2018 2017 Numerator: Net income (loss) available to WRD $ (115,774 ) $ 20,252 Less: Preferred stock dividends 7,389 — Net income (loss) available to common stockholders $ (123,163 ) $ 20,252 Denominator: Weighted-average common shares outstanding (in thousands) (1) 99,245 93,216 Basic EPS $ (1.24 ) $ 0.22 Diluted EPS (1) $ (1.24 ) $ 0.22 (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 months ended March 31, 2018. For the three months ended March 31, 2017, 6 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the three months ended March 31, 2018, 32,242 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)	3 Months Ended
	Mar. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Restricted Common Stock Awards Granted Under 2016 LTIP	The following table summarizes information regarding restricted common stock awards granted under the 2016 LTIP for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common stock outstanding at December 31, 2017 1,897,790 $ 13.95 Granted (2) 178,612 $ 18.14 Forfeited (34,407 ) $ 13.94 Vested (20,541 ) $ 14.08 Restricted common stock outstanding at March 31, 2018 2,021,454 $ 14.32 (1) Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common stock awards granted in 2018 was $3.2 million based on the grant date market price of $18.14 per share.

Segment Reporting (Tables)

Segment Reporting (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ (115,774 ) $ 20,252 Interest expense, net 13,307 5,571 Income tax (benefit) expense (38,093 ) 11,700 Depreciation, depletion and amortization 59,883 26,443 Exploration expense 1,708 1,615 Impairment of NLA Disposal Group 214,274 — (Gain) loss on derivative instruments 40,370 (31,291 ) Cash settlements received (paid) on derivative instruments (20,546 ) (983 ) Stock-based compensation 3,156 495 Acquisition related costs 359 599 Debt extinguishment costs — (11 ) Public offering costs — 182 Total Adjusted EBITDAX $ 158,644 $ 34,572

Organization and Basis of Pre40

Organization and Basis of Presentation - Additional Information (Details)	Mar. 31, 2018Subsidiary
Esquisto II
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries	2

Summary of Significant Accoun41

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 21,312	$ 656
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities	(34,893)	$ 25,528
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions	$ 4,229

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
ASSETS
Oil and gas properties	$ 2,734,096		$ 2,999,728
Accumulated depreciation, depletion and amortization	(280,362)		(368,245)
Other non-current assets	13,140
Liabilities:
Deferred tax liabilities	33,412		71,470
Stockholders’ equity:
Accumulated earnings (deficit)	(97,220)		$ 25,773
Accounting Standards Update 2014-09
ASSETS
Oil and gas properties		$ 2,995,687
Accumulated depreciation, depletion and amortization		(367,874)
Other non-current assets		3,978
Liabilities:
Deferred tax liabilities		71,537
Stockholders’ equity:
Accumulated earnings (deficit)		26,014
Adjustments for ASC 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	(4,484)	(4,041)
Accumulated depreciation, depletion and amortization	504	371
Other non-current assets	4,403	3,978
Liabilities:
Deferred tax liabilities	93	67
Stockholders’ equity:
Accumulated earnings (deficit)	328	$ 241
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	2,738,580
Accumulated depreciation, depletion and amortization	(280,866)
Other non-current assets	8,737
Liabilities:
Deferred tax liabilities	33,319
Stockholders’ equity:
Accumulated earnings (deficit)	$ (97,548)

Summary of Significant Accoun43

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Consolidated Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues and other income:
Oil sales	$ 182,379	$ 39,077
Natural gas sales	27,630	12,145
NGL sales	7,448	2,663
Other income	1,300	407
Operating expenses:
Lease operating expenses	16,427	6,928
Gathering, processing and transportation	1,352	1,700
Depreciation, depletion and amortization	59,883	26,443
Other operating (income) expense	658	19
Income (loss) before income taxes	(153,867)	31,952
Income tax benefit (expense)	38,093	(11,700)
Net income (loss)	(115,774)	$ 20,252
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Revenues and other income:
Oil sales	182,379
Natural gas sales	28,435
NGL sales	9,413
Other income	1,166
Operating expenses:
Lease operating expenses	16,433
Gathering, processing and transportation	4,103
Depreciation, depletion and amortization	60,016
Other operating (income) expense	518
Income (loss) before income taxes	(153,981)
Income tax benefit (expense)	38,120
Net income (loss)	(115,861)
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Revenues and other income:
Natural gas sales	(805)
NGL sales	(1,965)
Other income	134
Operating expenses:
Lease operating expenses	(6)
Gathering, processing and transportation	(2,751)
Depreciation, depletion and amortization	(133)
Other operating (income) expense	140
Income (loss) before income taxes	114
Income tax benefit (expense)	(27)
Net income (loss)	$ 87

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ (115,774)	$ 20,252
Depreciation, depletion and amortization	59,670	26,293
Deferred income tax expense (benefit)	(38,125)	11,700
Consideration paid to customers, net of amortization	(424)
Cash flows from investing activities:
Additions to oil and gas properties	(297,939)	$ (63,344)
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Cash flows from operating activities:
Net income (loss)	(115,861)
Depreciation, depletion and amortization	59,803
Deferred income tax expense (benefit)	(38,152)
Cash flows from investing activities:
Additions to oil and gas properties	(298,382)
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Cash flows from operating activities:
Net income (loss)	87
Depreciation, depletion and amortization	(133)
Deferred income tax expense (benefit)	27
Consideration paid to customers, net of amortization	(424)
Cash flows from investing activities:
Additions to oil and gas properties	$ 443

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Acquisition-Related Costs Included in General and Administrative Expenses (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Business Acquisition [Line Items]
Acquisition-related costs	$ 359	$ 599
General and Administrative Expense
Business Acquisition [Line Items]
Acquisition-related costs	$ 359	$ 599

Acquisitions and Divestitures46

Acquisitions and Divestitures - Additional Information (Details) shares in Millions	Mar. 29, 2018USD ($)	Mar. 01, 2018USD ($)	Feb. 12, 2018USD ($)	Feb. 01, 2018USD ($)	Jan. 04, 2018USD ($)a	Jun. 30, 2017shares	Feb. 02, 2017USD ($)Transaction	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Feb. 01, 2018USD ($)	Sep. 30, 2017
Business Acquisition [Line Items]
Payments to acquire other property, plant and equipment								$ 12,896,000	$ 1,521,000
Payment on Construction Deposits Related to Mine Development								8,738,000
Business acquisition, post-closing receipt									3,905,000
Proceeds from divestiture	$ 206,400,000
Deposits received			$ 21,700,000
Preliminary purchase price adjustments - consents not obtained	900,000
Preliminary purchase price adjustments - net cash flows effective date to closing date	$ 9,700,000
Contingent consideration arrangement divestiture			$ 35,000,000
Accrued divestiture contingent consideration receivable								400,000
Impairment of NLA Disposal Group								214,274,000	0
Pre-tax gain (loss) of NLA Disposal Group								(204,800,000)	1,100,000
Prepaid Expenses And Other Current Assets
Business Acquisition [Line Items]
NLA Assets held for sale								900,000
Sand Mine
Business Acquisition [Line Items]
Surface and sand rights acquired | a					727
Payments to acquire other property, plant and equipment					$ 9,000,000
Payment on Construction Deposits Related to Mine Development								$ 8,700,000
Producing and Non-producing properties in Lee County
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties		$ 18,600,000
Capitalized transaction costs		400,000
Purchase price allocated to unproved oil and natural gas properties		$ 16,900,000
APC/KKR Acquisitions
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties										$ 533,002,000
Business acquisition, date of acquisition agreement								May 10, 2017
Business acquisition, date of completion											Jun. 30, 2017
Business acquisition, post-closing receipt				$ 600,000
Business acquisition, aggregate purchase price, shares issued | shares						5.5
Third Parties Acquisition | Burleson County, TX
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties							$ 2,400,000
Purchase price allocated to unproved oil and natural gas properties							$ 2,300,000
Number of transactions closed as part of acquisition of oil and natural gas producing and non-producing properties | Transaction							1
December 2016 Eagle Ford Acquisition
Business Acquisition [Line Items]
Business acquisition, post-closing receipt									$ 3,900,000

Acquisitions and Divestitures47

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Details) - APC/KKR Acquisitions - USD ($) $ in Thousands	7 Months Ended
	Feb. 01, 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
Business Acquisition [Line Items]
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 Divestitures48

Acquisitions and Divestitures - Summary of Unaudited Pro Forma Financial Information (Details) - APC/KKR Acquisitions $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)$ / shares
Business Acquisition [Line Items]
Revenues	$ 79,203
Net income (loss)	$ 30,139
Earnings per share (basic and diluted) | $ / shares	$ 0.32

Fair Value Measurements of Fi49

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	Mar. 31, 2018	Dec. 31, 2017
Assets:
Fair value of derivative asset	$ 1,284	$ 2,422
Liabilities:
Fair value of derivative liability	91,760	76,750
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	1,284	2,422
Liabilities:
Fair value of derivative liability	$ 91,760	$ 76,750

Fair Value Measurements of Fi50

Fair Value Measurements of Financial Instruments - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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
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	$ 1,500,000	$ 700,000

Risk Management and Derivativ51

Risk Management and Derivative Instruments - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Deferred premiums	$ 2,500,000	$ 100,000
Derivative liabilities	90,500,000
Derivative liability, right to offset amount	0
Cash collateral received or pledged	$ 0

Risk Management and Derivativ52

Risk Management and Derivative Instruments - Schedule of Derivative Contracts (Details)	3 Months Ended
	Mar. 31, 2018$ / bblbbl
Crude Oil Derivative Contracts Fixed Price Swap Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	4,764,565
Weighted-average fixed price	52.39
Crude Oil Derivative Contracts Collar Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	12,208
Weighted-average floor price	50
Weighted-average ceiling price	62.10
Crude Oil Derivative Contracts Put Options Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	2,118,859
Weighted-average floor price	50.72
Weighted-average put premium	(3.56)
Crude Oil Derivative Contracts LLS Basis Swaps Remainder 2018
Derivative [Line Items]
Volume (Bbls) | bbl	2,804,384
Spread -WTI	3.05
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 Collar 2019
Derivative [Line Items]
Volume (Bbls) | bbl	0
Weighted-average floor price	0
Weighted-average ceiling price	0
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	1,101,762
Weighted-average fixed price	50.19
Crude Oil Derivative Contracts Collar 2020
Derivative [Line Items]
Volume (Bbls) | bbl	0
Weighted-average floor price	0
Weighted-average ceiling price	0
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

Risk Management and Derivativ53

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	Mar. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Liability Derivatives, Net recorded fair value	$ 90,500
Short-term Derivative Instruments | Commodity Derivative Contracts
Derivative [Line Items]
Asset Derivatives, Gross fair value	1,004	$ 2,336
Asset Derivatives, Netting arrangements	(1,004)	0
Asset Derivatives, Net recorded fair value	0	2,336
Liability Derivatives, Gross fair value	68,481	58,074
Liability Derivatives, Netting arrangements	(1,004)	0
Liability Derivatives, Net recorded fair value	67,477	58,074
Long-term Derivative Instruments | Commodity Derivative Contracts
Derivative [Line Items]
Asset Derivatives, Gross fair value	280	86
Asset Derivatives, Netting arrangements	(280)	0
Asset Derivatives, Net recorded fair value	0	86
Liability Derivatives, Gross fair value	23,279	18,676
Liability Derivatives, Netting arrangements	(280)	0
Liability Derivatives, Net recorded fair value	$ 22,999	$ 18,676

Risk Management and Derivativ54

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (40,370)	$ 31,291
Commodity Derivative Contracts
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ (40,370)	$ 31,291

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 72,872	$ 67,584
Joint interest billings	9,745	9,467
Severance tax	652	171
North Louisiana Settlement receivable	5,291	5,955
Environmental remediation	1,261	0
Other current receivables	2,969	1,026
Allowance for doubtful accounts	(200)	(100)	$ (100)
Total	$ 92,590	$ 84,103

Accounts Receivable - Schedul56

Accounts Receivable - Schedule of Accounts Notes Loans and Financing Receivable (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 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	0
Balance at end of period	$ 200	$ 100

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Payables And Accruals [Abstract]
Capital expenditures	$ 123,730	$ 162,260
Lease operating expense	5,536	5,796
General and administrative	4,793	1,642
Severance and ad valorem taxes	5,266	3,463
Interest expense	5,811	17,177
Derivative payable	7,612	5,281
Preferred stock cash dividends	4,480
Environmental liability	1,451
Income taxes		991
Other accrued liabilities	797	3,342
Total	$ 159,476	$ 199,952

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 14,557
Accretion expense	213	$ 150
Liabilities incurred	146
Disposition of wells and gathering system	(7,627)
Asset retirement obligations at end of period	7,289
Less: current portion	90
Asset retirement obligations – long-term	$ 7,199		$ 14,467

Long Term Debt - Schedule of De

Long Term Debt - Schedule of Debt Obligations (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (15,839)	$ (15,619)
Total long-term debt	793,686	770,596
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Long-term debt, gross	500,000	500,000
Unamortized discounts	(4,773)	(4,914)
Unamortized debt issuance costs	(10,541)	(10,843)
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	$ 309,000	$ 286,353

Long Term Debt - Schedule of 60

Long Term Debt - Schedule of Debt Obligations (Parenthetical) (Details) - 6.875% Senior Unsecured Notes, Due February 2025 - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 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	$ 501.3		$ 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	Mar. 31, 2018	Mar. 23, 2018	Mar. 22, 2018
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
WRD revolving credit facility	$ 1,050,000	$ 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	Mar. 31, 2018	Mar. 31, 2017	Sep. 30, 2017	Mar. 23, 2018	Mar. 22, 2018	Nov. 20, 2017
Debt Instrument [Line Items]
Proceeds from senior notes offering					$ 347,354
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Aggregate principal amount		$ 150,000	$ 350,000
Debt instrument interest rate percentage			6.875%
Issue price of notes as a percentage of par value		98.26%	99.244%
Proceeds from senior notes offering		$ 144,700	$ 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 | Subsequent Event
Debt Instrument [Line Items]
Aggregate principal amount	$ 200,000
Issue price of notes as a percentage of par value	102.00%
Proceeds from senior notes offering	$ 201,000
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
Revolving Credit Facility
Debt Instrument [Line Items]
Amount of borrowing base				$ 1,050,000			$ 1,050,000	$ 875,000

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Details)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	4.04%	3.52%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt issuance costs	$ 3,875	$ 3,573
Unamortized deferred financing costs	15,839	15,619
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Unamortized deferred financing costs	10,541	10,843
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Current	1,423	1,203
Debt issuance costs	$ 3,875	$ 3,573

Preferred Stock - Schedule of P

Preferred Stock - Schedule of Preferred Stock (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)
Class Of Stock [Line Items]
Balance at December 31, 2017	$ 445,483
Preferred stock paid-in-kind dividend	2,243
Balance at March 31, 2018	446,522
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
Unamortized beneficial conversion feature	(1,204)
Balance at March 31, 2018	$ 446,522

Preferred Stock - Additional In

Preferred Stock - Additional Information (Details) - USD ($) $ in Thousands	Apr. 30, 2018	Jan. 31, 2018	Mar. 31, 2018
Temporary Equity [Line Items]
Amortized beneficial conversion feature			$ 668
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity [Line Items]
Quarterly dividend announced date		Jan. 31, 2018
Quarterly dividend, amount		$ 6,656
Beneficial conversion feature			1,900
Amortized beneficial conversion feature			$ 700
Redeemable Convertible Preferred Stock | Cash Dividend | Subsequent Event
Temporary Equity [Line Items]
Quarterly dividend, amount	$ 6,756
Quarterly dividend, date paid	Apr. 30, 2018
Dividend, record date	Apr. 15, 2018

Equity - Additional Information

Equity - Additional Information (Details) - $ / shares	Mar. 31, 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) - Common Stock	3 Months Ended
	Mar. 31, 2018shares
Class Of Stock [Line Items]
Balance, Beginning of Period	101,137,277
Restricted common stock issued	178,612
Restricted common stock forfeited	(34,407)
Repurchase of vested restricted shares	(3,606)
Balance, End of Period	101,277,876

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
	Mar. 31, 2018	Mar. 31, 2017
Numerator:
Net income (loss) available to WRD	$ (115,774)	$ 20,252
Less: Preferred stock dividends	7,389	0
Net income (loss) available to common stockholders	$ (123,163)	$ 20,252
Denominator:
Weighted-average common shares outstanding	99,245	93,216
Basic	$ (1.24)	$ 0.22
Diluted	$ (1.24)	$ 0.22

Earnings Per Share - Schedule70

Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Parenthetical) (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares excluded in calculation of diluted EPS	32,242
Restricted Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Shares excluded in calculation of diluted EPS		6

Long Term Incentive Plans - Add

Long Term Incentive Plans - Additional Information (Details) - 2016 Long-Term Incentive Plan - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock authorized for issuance under plan	9,512,500
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized compensation expense	$ 3.2	$ 0.5
Unrecognized compensation cost	$ 21.3
Unrecognized compensation cost, weighted-average period	1 year 11 months 8 days

Long Term Incentive Plans - Sum

Long Term Incentive Plans - Summary of Restricted Common Stock Awards Granted Under 2016 LTIP (Details) - 2016 Long-Term Incentive Plan - Restricted Stock	3 Months Ended
	Mar. 31, 2018$ / sharesshares
Number of Shares
Restricted common shares outstanding, Beginning Balance | shares	1,897,790
Restricted commons shares, Granted | shares	178,612
Restricted commons shares, Forfeited | shares	(34,407)
Restricted commons shares, Vested | shares	(20,541)
Restricted common shares outstanding, Ending Balance | shares	2,021,454
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	18.14
Restricted common shares, Forfeited, Weighted-Average Grant Date Fair Value per Share | $ / shares	13.94
Restricted common shares, Vested, Weighted-Average Grant Date Fair Value per Share | $ / shares	14.08
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Ending Balance | $ / shares	$ 14.32

Long Term Incentive Plans - S73

Long Term Incentive Plans - Summary of Restricted Common Stock Awards Granted Under 2016 LTIP (Parenthetical) (Details) - 2016 Long-Term Incentive Plan $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value | $	$ 3.2
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price | $ / shares	$ 18.14

Incentive Units - Additional In

Incentive Units - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018USD ($)
Incentive Unit Valuation Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized compensation expense	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Jun. 30, 2017
Carlyle Group, L.P.
Related Party Transaction [Line Items]
Convertible preferred stock, shares issued			435,000
Genesis Energy Partners, L.P
Related Party Transaction [Line Items]
Proceeds from sale	$ 700,000	$ 900,000
NGP ECM
Related Party Transaction [Line Items]
Payments made to related party		100,000
Related party payments or receipts	$ 0
NGP ECM | Carlyle Group, L.P.
Related Party Transaction [Line Items]
Percentage of ownership interest in certain gross revenues	55.00%
NGP ECM | Carlyle Group, L.P. | NGP 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 | Carlyle Group, L.P. | NGP X US Holdings
Related Party Transaction [Line Items]
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds	40.00%
CH4 Energy
Related Party Transaction [Line Items]
Payments made to related party	$ 0	400,000
CH4 Energy | Office Rental and Parking
Related Party Transaction [Line Items]
Payments made to related party	100,000	100,000
CH4 Energy | Landman Services and Expenses Incurred in 2016
Related Party Transaction [Line Items]
Payments made to related party	$ 0	300,000
Service Providers
Related Party Transaction [Line Items]
Payments made to related party		$ 100,000

Segment Disclosures - Additiona

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

Segment Disclosures - Reconcili

Segment Disclosures - Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$ (115,774)	$ 20,252
Interest expense, net	13,307	5,571
Income tax (benefit) expense	(38,093)	11,700
Depreciation, depletion and amortization	59,883	26,443
Exploration expense	1,708	1,615
Impairment of NLA Disposal Group	214,274	0
(Gain) loss on derivative instruments	40,370	(31,291)
Cash settlements received (paid) on derivative instruments	(20,546)	(983)
Stock-based compensation	3,156	495
Acquisition-related costs	359	599
Debt extinguishment costs	0	(11)
Public offering costs	0	182
Total Adjusted EBITDAX	$ 158,644	$ 34,572

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	$ 38,093,000	$ (11,700,000)
Effective tax rate	24.80%	36.60%
Decrease in effective tax rate due to reduction in federal corporate income tax rate as a result of tax act	(11.80%)
Effective income tax rate reconciliation, at federal statutory income tax rate, percent	21.00%	35.00%	35.00%
Liability for unrecognized tax benefits	$ 0
Significant change to unrecognized tax benefits in next twelve months	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018USD ($)acre ft	Dec. 31, 2017USD ($)
Commitments And Contingencies [Line Items]
Accrued liability for existing and potential claims	$ 0	$ 0
Environmental obligations recognized	$ 1,500,000	$ 0
Interruptible water availability agreement, start date	Feb. 1, 2017
Interruptible water availability agreement, end date	Dec. 31, 2021
Interruptible Water Availability Agreement
Commitments And Contingencies [Line Items]
Aggregate of acre-feet of water per year | acre ft	6,978
Agreement payment	$ 500,000