Brazos Valley Longhorn, L.L.C. 10-Q 15 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
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	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		93,987,541

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 93,342	$ 3,115
Accounts receivable, net	27,046	26,428
Short-term derivative instruments	5,674
Prepaid expenses and other current assets	2,310	1,633
Total current assets	128,372	31,176
Property and equipment:
Oil and gas properties	1,666,340	1,573,848
Other property and equipment	36,893	34,344
Accumulated depreciation, depletion and amortization	(226,587)	(200,293)
Total property and equipment, net	1,476,646	1,407,899
Other noncurrent assets:
Restricted cash	752	886
Long-term derivative instruments	8,393
Debt issuance costs	1,954	2,320
Other long-term assets	1,319
Total assets	1,617,436	1,442,281
Current liabilities:
Accounts payable	19,751	21,014
Accrued liabilities	56,003	23,371
Short-term derivative instruments	4,708	14,087
Asset retirement obligations	90	90
Total current liabilities	80,552	58,562
Noncurrent liabilities:
Long-term debt	338,783	242,750
Asset retirement obligations	10,868	10,943
Deferred tax liabilities	124,253	112,552
Long-term derivative instruments	367	8,091
Other noncurrent liabilities	1,393	1,495
Total noncurrent liabilities	475,664	375,831
Total liabilities	556,216	434,393
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding
Common stock, $0.01 par value 500,000,000 shares authorized; 93,987,541 shares and 91,680,441 shares issued and outstanding at March 31, 2017 and December 31, 2016, respectively	940	917
Additional paid-in capital	1,050,425	1,017,368
Accumulated earnings (deficit)	9,855	(10,397)
Total stockholders’ equity	1,061,220	1,007,888
Total liabilities and equity	$ 1,617,436	$ 1,442,281

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	93,987,541	91,680,441
Common stock, shares outstanding	93,987,541	91,680,441

STATEMENTS OF UNAUDITED CONDENS

STATEMENTS OF UNAUDITED CONDENSED CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues:
Oil sales	$ 39,077	$ 13,253
Natural gas sales	12,145	10,206
NGL sales	2,663	945
Other income	407	723
Total operating revenues	54,292	25,127
Operating expenses:
Lease operating expenses	6,928	2,760
Gathering, processing and transportation	1,700	1,891
Gathering system operating expense	19	54
Taxes other than income tax	3,899	1,472
Depreciation, depletion and amortization	26,443	22,063
General and administrative	7,482	4,449
Exploration expense	1,615	7,443
Total operating expense	48,086	40,132
Income (loss) from operations	6,206	(15,005)
Other income (expense):
Interest expense, net	(5,571)	(1,972)
Debt extinguishment costs	11	(358)
Gain (loss) on derivative instruments	31,291	3,246
Other income (expense)	15	12
Total other income (expense)	25,746	928
Income (loss) before income taxes	31,952	(14,077)
Income tax benefit (expense)	(11,700)	(139)
Net income (loss)	20,252	(14,216)
Net income (loss) attributable to previous owner		(2,517)
Net income (loss) attributable to predecessor		$ (11,699)
Net income (loss) available to WildHorse Resources	$ 20,252
Earnings per common share:
Basic	$ 0.22
Diluted	$ 0.22
Weighted-average common shares outstanding:
Basic	93,216
Diluted	93,216

STATEMENTS OF UNAUDITED CONDEN5

STATEMENTS OF UNAUDITED CONDENSED CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 20,252	$ (14,216)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	26,293	21,965
Accretion of asset retirement obligations	150	98
Dry hole expense and impairments of unproved properties	683
Amortization of debt issuance cost	838	117
(Gain) loss on derivative instruments	(31,291)	(3,246)
Cash settlements on derivative instruments	(983)	3,373
Accretion of senior note discount	42
Deferred income tax expense (benefit)	11,700	114
Debt extinguishment expense	(11)	358
Amortization of equity awards	495
Changes in operating assets and liabilities
Decrease (increase) in accounts receivable	(8,047)	(4,534)
Decrease (increase) in prepaid expenses	(735)	177
Decrease (increase) in inventories		1,728
(Decrease) increase in accounts payable and accrued liabilities	8,433	(9,003)
Net cash flow provided by (used in) operating activities	27,819	(3,069)
Cash flows from investing activities:
Acquisitions of oil and gas properties	(3,019)	(2,201)
Acquisition post-closing adjustment receipts	3,905
Additions to oil and gas properties	(63,345)	(39,821)
Additions to and acquisitions of other property and equipment	(1,521)	(2,288)
Acquisition deposits	(1,319)
Change in restricted cash	135	(86)
Net cash used in investing activities	(65,164)	(44,396)
Cash flows from financing activities:
Advances on revolving credit facilities	15,500	84,000
Payments on revolving credit facilities	(258,250)	(77,000)
Debt issuance cost	(9,016)	(431)
Termination of second lien		(225)
Proceeds from senior notes offering	347,354
Predecessor contributions		12,776
Net cash provided by financing activities	127,572	19,120
Net change in cash and cash equivalents	90,227	(28,345)
Cash and cash equivalents, beginning of period	3,115	43,126
Cash and cash equivalents, end of period	93,342	$ 14,781
Over-allotment Option
Cash flows from financing activities:
Proceeds from over-allotment option	34,457
Cost incurred in conjunction with stock issuance	(1,872)
Initial Public Offering
Cash flows from financing activities:
Cost incurred in conjunction with stock issuance	$ (601)

UNAUDITED CONDENSED CONSOLIDAT6

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - 3 months ended Mar. 31, 2017 - USD ($) $ in Thousands	Total	Over-allotment Option	Common Stock	Common StockOver-allotment Option	Additional Paid in Capital	Additional Paid in CapitalOver-allotment Option	Accumulated Earnings (deficit)
Balance at Dec. 31, 2016	$ 1,007,888		$ 917		$ 1,017,368		$ (10,397)
Net income (loss)	20,252						20,252
Proceeds from over-allotment option		$ 34,457		$ 23		$ 34,434
Costs incurred in connection with over-allotment option		$ (1,872)				$ (1,872)
Amortization of equity awards	495				495
Balance at Mar. 31, 2017	$ 1,061,220		$ 940		$ 1,050,425		$ 9,855

Organization and Basis of Prese

Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation WildHorse Resource Development Corporation is a publicly traded Delaware corporation, the common shares of which are listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “WRD,” or “the Company” are intended to mean the business and operations of WildHorse Resource Development Corporation and its consolidated subsidiaries. We are an independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Reference to “WHR II” or our “predecessor” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries. Reference to “Esquisto I” refers to Esquisto Resources, LLC. Reference to “Esquisto II” refers to Esquisto Resources II, LLC. Reference to “Esquisto Merger” refers to the merger of Esquisto I with and into Esquisto II on January 12, 2016. Reference to “Esquisto” refers (i) for the period beginning February 17, 2015 (date of common control) through January 11, 2016, to Esquisto I and Esquisto II on a combined basis and (ii) for the period beginning January 12, 2016 through the completion of our initial public offering on December 19, 2016, to Esquisto II. Reference to “Acquisition Co.” refers to WHE AcqCo., LLC, an entity that was formed to acquire the Burleson North assets (see Note 3—Acquisitions and Divestitures). Reference to “WildHorse Investment Holdings” refers to WildHorse Investment Holdings, LLC. Reference to “Previous owner” refers to both Esquisto and Acquisition Co.. Reference to “Esquisto Investment Holdings” refers to Esquisto Investment Holdings, LLC. Reference to “WildHorse Holdings” refers to WHR Holdings, LLC. Reference to “Esquisto Holdings” refers to Esquisto Holdings, LLC. Reference to “Acquisition Co. Holdings” refers to WHE AcqCo Holdings, LLC. Reference to “NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in WHR II, Esquisto and Acquisition Co. Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation. WHR II has two wholly owned subsidiaries – WildHorse Resources Management Company, LLC (“WHRM”) and Oakfield Energy LLC (“Oakfield”). Esquisto has two wholly owned subsidiaries – Petromax E&P Burleson, LLC and Burleson Water Resources, LLC. WHRM is the named operator for all oil and natural gas properties owned by us. Basis of Presentation Our predecessor’s financial statements were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the financial statements included herein for the three months ended March 31, 2016 have been derived from the combined financial position and results attributable to our predecessor and Esquisto. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. Oakfield drip condensate was reclassified from oil sales to other income. All material intercompany transactions and balances have been eliminated in preparation of our condensed consolidated and combined financial statements. The accompanying condensed consolidated and combined 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 and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations (“ARO”); (6) environmental remediation costs; (7) valuation of derivative instruments; (8) contingent liabilities and (9) 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, 2017
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 2016 Form 10-K. Supplemental Cash Flow Information Supplement cash flow for the periods presented (in thousands): For the Three Months Ended March 31, 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 656 $ 1,882 Noncash investing activities: Increase in capital expenditures in accounts payables and accrued liabilities 25,528 6,535 New Accounting Standards Improvements to Employee Share-Based Payment Accounting. In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involved several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. This new standard became effective for annual periods beginning after December 15, 2016. The Company adopted this guidance as of January 1, 2017 and it did not have a material impact on our consolidated financial statements. We elected to account for forfeitures on share-based payments by recognizing forfeitures of awards as they occur. 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, 2017
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 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, 2017 2016 $ 599 $ — 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. See “Note 18—Subsequent Events” for further information. 2016 Acquisitions Burleson North Acquisition . As discussed in our 2016 Form 10-K, we completed an acquisition of approximately 158,000 net acres of oil and natural gas properties adjacent to our existing Eagle Ford acreage on December 19, 2016 in connection with our initial public offering (the “Burleson North Acquisition”). Funds wired on December 19, 2016 were $389.8 million. During the three months ending March 31, 2017, we received a post-closing receipt of $3.9 million. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands). We allocated $162.9 million of the purchase price to unproved oil and natural gas properties. Purchase Price Oil and natural gas properties $ 395,591 Other property and equipment 478 Accounts receivable 1,257 Accounts payable (1,816 ) Asset retirement obligations (3,101 ) Accrued liabilities (6,503 ) Total identifiable net assets $ 385,906 Supplemental Pro forma Information . The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2016 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Three Months Ended March 31, 2016 Revenues $ 35,334 Net income (loss) (14,229 ) Basic and diluted earnings per unit n/a

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). 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, 2017 and December 31, 2016. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. The fair market values of the derivative financial instruments reflected on the balance sheets as of March 31, 2017 and December 31, 2016 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Fair Value Measurements at March 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 $ — $ 15,689 $ — $ 15,689 Liabilities: Commodity derivatives $ — $ 6,697 $ — $ 6,697 Fair Value Measurements at December 31, 2016 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 7 $ — $ 7 Liabilities: Commodity derivatives $ — $ 22,185 $ — $ 22,185 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: • The fair value of 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 during the three months ended March 31, 2017 and 2016. • 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, 2017, we recorded $0.7 million of impairments of unproved properties. We did not record any impairments for the three months ended March 31, 2016.

Risk Management and Derivative

Risk Management and Derivative Instruments	3 Months Ended
	Mar. 31, 2017
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, collars and deferred purchased puts to accomplish our hedging strategy. Collars consist of a sold call and a purchased put that establishes 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, 2017 is net of deferred premiums of $0.1 million. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, specifically only lenders under our revolving credit facility. These transactions 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. See “Note 4—Fair Value Measurements of Financial Instruments” for further information. The following derivative contracts were in place at March 31, 2017: Remainder 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 6,346,000 11,565,800 9,877,900 Weighted-average fixed price $ 3.15 $ 3.03 $ 2.81 Collar contracts: Volume (MMBtu) 4,140,000 — — Weighted-average floor price $ 3.00 $ — $ — Weighted-average ceiling price $ 3.36 $ — $ — Put options: Volume (MMBtu) 3,095,895 — — Weighted-average floor price $ 3.40 $ — $ — Weighted-average put premium $ (0.37 ) $ — $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 1,526,900 1,638,500 1,381,300 Weighted-average fixed price $ 52.82 $ 53.68 $ 54.92 Collar contracts: Volume (Bbls) 43,872 25,096 — Weighted-average floor price $ 50.00 $ 50.00 $ — Weighted-average ceiling price $ 62.10 $ 62.10 $ — Put options: Volume (Bbls) 1,325,036 — — Weighted-average floor price $ 55.00 $ — $ — Weighted-average put premium $ (4.77 ) $ — $ — 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, 2017 and December 31, 2016. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives March 31, December 31, March 31, December 31, Type Balance Sheet Location 2017 2016 2017 2016 Commodity contracts Short-term derivative instruments $ 6,626 $ 4 $ 5,660 $ 14,091 Netting arrangements Short-term derivative instruments (952 ) (4 ) (952 ) (4 ) Net recorded fair value $ 5,674 $ — $ 4,708 $ 14,087 Commodity contacts Long-term derivative instruments $ 9,063 $ 3 $ 1,037 $ 8,094 Netting arrangements Long-term derivative instruments (670 ) (3 ) (670 ) (3 ) Net recorded fair value $ 8,393 $ — $ 367 $ 8,091 (Gains) & Losses on Derivatives All gains and losses, including changes in the derivative instruments’ fair values, are included as a component of “Other income (expense)” in the Statements of Unaudited Condensed Consolidated and Combined Operations. The following table details the gains and losses related to derivative instruments for the three months ending March 31, 2017 and 2016 (in thousands): Statements of For the Three Months Ended March 31, Operations Location 2017 2016 Commodity derivative contracts (Gain) $ (31,291 ) $ (3,246 )

Accounts Receivable

Accounts Receivable	3 Months Ended
	Mar. 31, 2017
Receivables [Abstract]
Accounts Receivable	Note 6. Accounts Receivable Accounts receivable consist of the following (in thousands): March 31, December 31, 2017 2016 Oil, natural gas and NGL sales $ 17,309 $ 13,390 Joint interest billings 8,993 7,898 Severance tax 89 392 Other current receivables 755 4,848 Allowance for doubtful accounts (100 ) (100 ) Total $ 27,046 $ 26,428

Accrued Liabilities

Accrued Liabilities	3 Months Ended
	Mar. 31, 2017
Payables And Accruals [Abstract]
Accrued Liabilities	Note 7. Accrued Liabilities Accrued liabilities consist of the following (in thousands): March 31, December 31, 2017 2016 Capital expenditures $ 43,462 $ 17,934 Deferred rent 392 386 Lease operating expense 2,565 2,608 General and administrative 2,849 1,471 Severance and ad valorem taxes 2,220 194 Interest expense 4,014 346 Other accrued liabilities 501 432 Total $ 56,003 $ 23,371

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2017
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, 2017 (in thousands): Asset retirement obligations at beginning of period $ 11,033 Accretion expense 150 Liabilities incurred 60 Revisions (285 ) Asset retirement obligations at end of period 10,958 Less: current portion (90 ) Asset retirement obligations – long-term $ 10,868

Long Term Debt

Long Term Debt	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Long Term Debt	Note 9. Long Term Debt Our debt obligations consisted of the following at the dates indicated (in thousands): For the Year Ended December 31, Credit Facility 2017 2016 WRD revolving credit facility $ — $ 242,750 6.875% senior unsecured notes, due February 2025 (1) 350,000 — Unamortized discounts (2,604 ) — Unamortized debt issuance costs - 6.875% senior unsecured notes (8,613 ) — Total long-term debt $ 338,783 $ 242,750 (1) The estimated fair value of this fixed-rate debt was $338.2 million at March 31, 2017. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. Borrowing Base Credit facilities tied to borrowing base are common throughout the oil and natural gas industry. Our borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for our credit facility was the following at the date indicated (in thousands): March 31, Credit Facility 2017 WRD revolving credit facility $ 362,500 Subsequent Events . On April 4, 2017, WRD’s revolving credit facility borrowing base was increased to $450.0 million in connection with the semi-annual borrowing redetermination by the lenders. On April 27, 2017, standby letters of credit of $1.9 million were issued to the Railroad Commission of Texas under our revolving credit facility. 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. 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). The consummation of our 2025 Senior Notes offering automatically reduced the borrowing base of our revolving credit facility by $87.5 million. The net proceeds from the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes. 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. In connection with the issuance and sale of the 2025 Senior Notes, the Company and our subsidiary guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with a representative of the initial purchasers of the 2025 Senior Notes, dated February 1, 2017. Pursuant to the Registration Rights Agreement, we agreed to file a registration statement with the SEC so that holders of the 2025 Senior Notes can exchange the 2025 Senior Notes for registered notes that have substantially identical terms. In addition, we have agreed to exchange the guarantees related to the 2025 Senior Notes for registered guarantees having substantially the same terms as the original guarantees. The Company and the guarantors will use commercially reasonable best efforts to cause the exchange to be consummated within 365 days after the issuance of the 2025 Senior Notes. The Company and the guarantors are required to pay additional interest if they fail to comply with their obligations to register the 2025 Senior Notes within the specified time periods. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: For the Three Months Ended March 31, Credit Facility 2017 2016 WRD revolving credit facility 3.52 % n/a WHR II revolving credit facility terminated December 2016 n/a 3.00 % Esquisto - revolving credit facility terminated December 2016 n/a 2.81 % Esquisto - revolving credit facility terminated January 2016 n/a 2.97 % Esquisto - Second lien terminated in January 2016 n/a 9.50 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands): March 31, December 31, 2017 2016 WRD revolving credit facility (1) $ 2,479 $ 2,904 6.875% senior unsecured notes, due February 2025 8,613 n/a Total $ 11,092 $ 2,904 (1) We classified $0.5 million and $0.6 million of unamortized deferred financing costs at March 31, 2017 and December 31, 2016, respectively, under current assets as a component of “prepaid expenses and other current assets.”

Equity

Equity	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Equity	Note 10. Equity Common Stock The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the three months ended March 31, 2017: Balance, December 31, 2016 91,680,441 Common stock issued 2,297,100 Restricted common stock issued 10,000 Balance, March 31, 2017 93,987,541 On January 17, 2017, we issued and sold 2,297,100 shares of our common stock at an offering price of $15.00 per share pursuant to the partial exercise of the underwriters’ over-allotment option associated with our initial public offering the (“Option Exercise”). We received net proceeds of $32.6 million from the Option Exercise, all of which was used to repay outstanding borrowings under our revolving credit facility. See “Note 12—Long Term Incentive Plan” for additional information regarding the shares of restricted common stock that were granted in connection with our initial public offering. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award. Predecessor Equity The predecessor received capital contributions of $12.8 million from its members during the three months ended March 31, 2016.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	Note 11. Earnings per share The following sets forth the calculation of earnings (loss) per share, or EPS, for the three months ending March 31, 2017 (in thousands, except per share amounts): Numerator: Net income (loss) available to WildHorse Resources $ 20,252 Denominator: Weighted-average common shares outstanding (in thousands) (1) 93,216 Basic EPS $ 0.22 Diluted EPS (1) $ 0.22 (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for the three months ended March 31, 2017. For the three months ended March 31, 2017, 6 incremental shares were included in the calculation of diluted EPS under the treasury stock method.

Long Term Incentive Plans

Long Term Incentive Plans	3 Months Ended
	Mar. 31, 2017
Long Term Incentive Plans
Long Term Incentive Plans	Note 12. 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, 2016 353,334 $ 14.50 Granted (2) 10,000 $ 14.22 Restricted common stock outstanding at March 31, 2017 363,334 $ 14.49 (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 2017 was $0.1 million based on grant date market price of $14.22 per share. For the three months ended March 31, 2017, we recorded $0.5 million of recognized compensation expense associated with these awards. Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $4.7 million at March 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.58 years.

Incentive Units

Incentive Units	3 Months Ended
	Mar. 31, 2017
Compensation Related Costs [Abstract]
Incentive Units	Note 13. Incentive Units The governing documents of WHR II provided for the issuance of incentive units. WHR II granted incentive units to certain of its members who were key employees at the time of grant. The incentive units were accounted for similar to liability-classified awards as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. The payment likelihood related to the WHR II incentive units was not deemed probable for the three months ended March 31, 2016. As such, no compensation expense was recognized by our predecessor. In connection with the Corporate Reorganization, the WHR II incentive units were transferred to WildHorse Investment Holdings in exchange for substantially similar incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings granted certain officers and employees awards of incentive units in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The fair value of the incentive units will be remeasured on a quarterly basis until all payments have been made. Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. The payment likelihood related to these incentive units was not deemed probable at March 31, 2017. As such, no compensation expense was recognized by us. Unrecognized compensation costs associated with these incentive units was $27.6 million at March 31, 2017. The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following key assumptions: Incentive Unit Valuation As Of March 31, 2017 Expected life (years) 1.29 - 5.54 Expected volatility (range) 57.0% - 64.0% Dividend yield 0.0% Risk-free rate (range) 1.09% - 1.99%

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 14. 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, 2017, we received $0.9 million from Genesis. NGP Affiliated Companies Highmark Energy Operating, LLC. During the three months ended March 31, 2017 and 2016, we received net payments of less than $0.1 million and $0.2 million, respectively, from Highmark Energy Operating, LLC, a NGP affiliated company, for non-operated working interests in oil and natural gas properties we operate. Cretic Energy Services, LLC. During the three months ended 2016, we made payments of $0.1 million to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. We did not record any related party payments or receipts for the three months ended March 31, 2017. PennTex Midstream Partners, LP. During the three months ended March 31, 2016, we made net payments of less than $0.1 million to PennTex Midstream Partners, LP (“PennTex”), a former NGP affiliated company, for the gathering, processing and transportation of natural gas and NGLs. Our related party relationship ceased in the fall of 2016 when a third-party acquired controlling interests in PennTex. WildHorse Resources, LLC . WildHorse Resources, LLC (“WHR”), an entity formerly under common control with WHR II, ceased being a related party in September 2016 when its parent company was acquired by a third party. During the three months ended March 31, 2016, we paid net payments of less than $0.1 million to WHR’s parent company for non-operated working interests in oil and natural gas properties we operate. NGP X US Holdings LP. Our predecessor paid NGP X US Holdings LP. less than $0.1 million during the three months ended March 31, 2016 for director fees. CH4 Energy. CH4 Energy entities are NGP affiliated companies and Mr. Brannon is President of these entities. During the three months ended March 31, 2017 we had net receipts of $0.3 million from certain CH4 Energy entities for non-operated working interests in oil and natural gas properties we operate. We did not have any related party payments or receipts for the three months ended March 31, 2016. Promissory Notes. WHR II issued promissory notes in favor of certain members of WHR II’s management to fund future capital commitments and carried an interest rate of 2.5% . On November, 9, 2016, the management members conveyed to the predecessor certain ownership interests in the predecessor in exchange for the discharge in full and the termination of all the promissory note advances then outstanding. There were no management payments of promissory note interest during the three months ended March 31, 2016. Previous Owner Related Party Transactions Notes payable to members. During the three months ended March 31, 2016, Esquisto accrued $1.0 million, as general and administrative expenses payable to its members. In connection with our initial public offering, the Esquisto notes payable to its members were paid off. Services provided by member. Esquisto paid Calbri Energy, Inc. (“Calbri”), a less than 1% former owner, $0.1 million for the three months ended March 31, 2016, for completion consulting services. Operator. Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $0.3 million during the three months ended March 31, 2016 for overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements and in accordance with an operating agreement between Petromax and Esquisto. Petromax is owned 33.3% by Mike Hoover, the former Chief Operating Officer of Esquisto, who also indirectly owned one of the former members of Esquisto. Related Party Agreements Registration Rights Agreement and Stockholders’ Agreement A discussion of these agreements is included in our 2016 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 will pay a monthly management fee to the Service Providers. NGP and certain former management members of Esquisto own the Service Providers. During the three months ended March 31, 2017, we paid the Service Providers $0.1 million.

Segment Disclosures

Segment Disclosures	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Segment Disclosures	Note 15. Segment Disclosures Our chief executive officer has been identified as our chief operating decision maker (“CODM”). We have identified two operating segments – the Eagle Ford and North Louisiana – that have been aggregated into one reportable segment that is engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources in the United States. Our reportable segment includes midstream operations that primarily support the Company’s oil and 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 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, 2017 2016 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 20,252 $ (14,216 ) Interest expense, net 5,571 1,972 Income tax (benefit) expense 11,700 139 Depreciation, depletion and amortization 26,443 22,063 Exploration expense 1,615 7,443 (Gain) loss on derivative instruments (31,291 ) (3,246 ) Cash settlements received (paid) on derivative instruments (983 ) 3,373 Stock-based compensation 495 — Acquisition related costs 599 — Debt extinguishment costs (11 ) 358 Public offering costs 182 — Non-cash liability amortization — (183 ) Total Adjusted EBITDAX $ 34,572 $ 17,703

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 16. Income Taxes The Company is a corporation subject to federal and state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes; however, one of our predecessor subsidiaries previously elected to be taxed as a corporation and was subject to federal and state income taxes. Income tax expense for the three months ended March 31, 2017 was $11.7 million compared to income tax expense of $0.1 million for the three months ended March 31, 2016. The period-to-period increase was primarily a result of being a corporation subject to federal and state income tax subsequent to our initial public offering. The effective tax rate for the three months ended March 31, 2017 and 2016 was 36.6% and negative 1.0%, respectively. The effective tax rate differed from the statutory federal income tax rate during the three months ended March 31, 2017 primarily due to the impact of state income tax (net of federal benefit). The effective tax rate differed from the statutory federal income tax rate during the three months ended March 31, 2016 primarily due to the impact of pass-through entities and state income tax (net of federal benefit). The Company reported no liability for unrecognized tax benefits as of March 31, 2017 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, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 17. Commitments and Contingencies Litigation & Environmental We are party to various ongoing and threatened legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of March 31, 2017 and December 31, 2016. Our estimates are based on information known about the matters and the input of attorneys experienced in contesting, litigating, and settling similar matters. Actual amounts could differ from our estimates and other claims could be asserted. From time to time, we could be liable for environmental claims arising in the ordinary course of business. No environmental obligations were recognized at March 31, 2017 and December 31, 2016. Firm Gas Transportation Service Agreement The Company has an existing firm gas transportation service agreement with Regency Intrastate Gas LLC as discussed in our 2016 Form 10-K. Letters of Credit and Certificate of Deposit The company has existing standby letters of credit issued to the Louisiana Office of Conservation and the Railroad Commission of Texas. These standby letters of credit are cash collateralized by certificates of deposits. The fair value of the certificates of deposits were $0.8 million and $0.9 million at March 31, 2017 and December 31, 2016, respectively, and were recorded on our balance sheet as restricted cash. Dedicated Fracturing Fleet Services Agreement During the three months ended March 31, 2017, the Company entered into a 20-month dedicated fracturing fleet services agreement to complete wells in a timely manner following conclusion of drilling operations. The agreement may be extended for an additional twelve months. We have agreed to pay a fixed monthly service fee of $2.7 million that covers the cost of equipment and personnel. In addition to the fixed monthly service charge, we have agreed to pay $6,000 for each stage completed in excess of 360 stages per calendar quarter. We have also agreed to pay a pass through fee for the cost of chemicals and fuel plus 10%. We have the right to terminate the contract with appropriate notice; however, an early termination fee of approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on the termination date. Interruptible Water Availability Agreement The Company entered into an interruptible water availability agreement with the Brazos River Authority (“BRA”) that began on February 1, 2017 and ends on December 31, 2021. The agreement provides us with an aggregate of 6,978 acre-feet of water per year from the Brazos River at prices that may be adjusted periodically by BRA. The agreement requires annual payments to be made on or before February 15 of each year during the term of the agreement. We recorded a payment of $0.4 million during the three months ended March 31, 2017.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 18. Subsequent Events APC/KKR Acquisition On May 10, 2017, we, through our new wholly owned subsidiary, WHR Eagle Ford LLC (“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”), Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “KKR” and, together with APC, the “First Sellers”), as sellers, to acquire certain acres 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 acres and associated production in Burleson, Brazos, Lee, Milam, Robertson, and Washington Counties, Texas (together, with the Purchase, the “Acquisition”). Pursuant to the Acquisition Agreements, we are acquiring approximately 111,000 aggregate net acres and the associated production therefrom. The aggregate purchase price for the assets, as described in the Acquisition Agreements, subject to customary adjustments as provided in the Acquisition Agreements, consists of approximately $556 million of cash to the APC Subs, as applicable, and approximately 6.3 million shares of our common stock valued at approximately $69 million to KKR (in the aggregate, the “Purchase Price”). The common stock portion of the Purchase price payable to KKR will be issued pursuant to a Stock Issuance Agreement that was executed, on May 10, 2017 (the “Stock Issuance Agreement”), by and among us and KKR. We and KKR have made customary representations, warranties and covenants in the Stock Issuance Agreement. The closing of the common stock issuance is conditioned upon and will occur simultaneous with the closing of the Acquisition. We and the Sellers have made customary representations, warranties and covenants in the Acquisition Agreements. The Sellers have made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Acquisition Agreements and the closing of the Acquisition and not to engage in certain kinds of transactions during that period, subject to certain exceptions. The Sellers have agreed not to take certain specified actions without our consent during the time between execution of the Acquisition Agreements and the closing of the Acquisition. Consummation of the Acquisition is subject to customary conditions. The Acquisition is expected to close on or about June 30, 2017 with an effective date of January 1, 2017. The Acquisition Agreements may be terminated under customary circumstances. Preferred Stock Issuance To partially fund the cash portion of the Purchase Price, on May 10, 2017, we entered in to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (“Carlyle”), an affiliate of The Carlyle Group, whereby we agreed to issue and sell to Carlyle, and Carlyle agreed to purchase from us, 435,000 shares of our preferred stock, par value $0.01 per share, designated as “Series A Perpetual Convertible Preferred Stock” (the “Preferred Stock”), having terms set forth in the Certificate of Designations, a form of which is an annex to the Preferred Stock Purchase Agreement. The Preferred Stock will rank senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock will have an initial liquidation preference of $1,000 per share and will pay a dividend rate of 6% per annum in cash or, if a cash dividend is not declared and paid in respect of any dividend payment period, by adding additional amounts to the liquidation preference in kind. The Preferred Stock will also participate in dividends and distributions on our common stock on an as-converted basis. If at any time following the 30-month anniversary of the issuance date the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently. The Preferred Stock is convertible at the option of the holders at any time following the first anniversary of the closing date into the amount of shares of common stock per share of Preferred Stock (such rate, the “Conversion Rate”) equal to (i) the quotient of (A) the sum of the Liquidation Preference (as defined in the Preferred Stock Purchase Agreement) plus an amount equal to the accrued but unpaid dividends and distributions not previously added to the Liquidation Preference divided by (B) a conversion price of $13.90 (the “Conversion Price”), subject to customary anti-dilution adjustments. The holders of Preferred Stock may also convert their Preferred Stock at the Conversion Rate prior to the first anniversary of the closing date in connection with certain change of control transactions and in connection with sales of common stock by certain of our existing shareholders. Following the fourth anniversary of the closing date, the Company may cause the conversion of the Preferred Stock at the Conversion Rate, provided the closing sale price of the common stock equals or exceeds 140% of the Conversion Price for the 20 trading days ending on and including the date of delivery of the Company’s notice to convert and subject to certain other requirements regarding registration of the shares issuable upon conversion. Notwithstanding the foregoing, the Company shall only be permitted to deliver one conversion notice during any 180 day period and the number of shares of common stock issued upon conversion of the Preferred Stock for which such automatic conversion notice is given shall be limited to 25 times the average daily trading volume of our common stock during the 20 trading days ending on and including the date of delivery of the Company’s notice to convert. If the Company undergoes certain change of control transactions, the holders of the Preferred Stock shall be entitled to cause the Company to redeem the Preferred Stock for cash in an amount equal to the Liquidation Preference, plus the net present value of dividend payments that would have been accrued as payable to the holders following the date of the consummation of such change of control and through the day that is 30 months after the closing date, in the case of any change of control occurring prior to the 30-month anniversary of the closing date (the “COC Redemption Price”). In addition, the Company will have the right in connection with any such change of control transaction to redeem any Preferred Stock that is not otherwise converted or redeemed as described in the preceding sentence for cash at the COC Redemption Price. At any time after the fifth anniversary of the closing date, the Company may redeem the Preferred Stock, in whole or in part, for an amount in cash equal to, per each share of Preferred Stock, (i) on or prior to the sixth anniversary of the closing date, the Liquidation Preference multiplied by 112%, (ii) on or prior to the seventh anniversary of the closing date, the Liquidation Preference multiplied by 109% or (ii) after the seventh anniversary of the closing date, the Liquidation Preference multiplied by 106%. Until conversion, the holders of the Preferred Stock will vote together with our common stock on an as-converted basis and will also have rights to vote as a separate class on certain matters impacting the Preferred Stock. However, the Preferred Stock will not be entitled to vote with the common stock on an as-converted basis, will not be convertible into our common stock and will not be entitled to the board election rights described below until the later of (i) the 21st day after the date on which we mail to our shareholders an information statement regarding the issuance of the Preferred Stock and (ii) the date certain required regulatory approvals are obtained. In addition, Carlyle as a holder of Preferred Stock will be entitled to elect (i) two directors to our board of directors for so long as Carlyle owns 10% of our outstanding common stock on an as-converted basis and (ii) one board seat for so long as Carlyle holds 5% of our outstanding common stock on an as-converted basis. The closing of the Preferred Stock issuance is conditioned upon and will close simultaneously with the closing of the Acquisition. As conditions to closing under the Stock Issuance Agreement and the Preferred Purchase Agreement we have agreed to amend and restate our existing registration rights agreement with WHR Holdings, LLC, Esquisto Holdings, LLC, WHE AcqCo Holdings, LLC, NGP XI US Holdings, L.P., Jay C. Graham and Anthony Bahr in order to grant certain registration rights to KKR and Carlyle. The remainder of the cash portion of the Purchase Price is to be funded by borrowings under our revolving credit facility. Eagle Ford Acquisitions In February 2017, we announced multiple transactions to acquire certain oil and natural gas producing and non-producing properties from third-parties in Burleson County, Texas. We closed one transaction in February 2017 as discussed in “Note 3—Acquisitions and Divestitures.” The remaining transactions closed in April 2017 for an aggregate price of approximately $13.2 million, subject to customary post-closing adjustments.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our predecessor’s financial statements were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the financial statements included herein for the three months ended March 31, 2016 have been derived from the combined financial position and results attributable to our predecessor and Esquisto. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. Oakfield drip condensate was reclassified from oil sales to other income. All material intercompany transactions and balances have been eliminated in preparation of our condensed consolidated and combined financial statements. The accompanying condensed consolidated and combined 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 and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations (“ARO”); (6) environmental remediation costs; (7) valuation of derivative instruments; (8) contingent liabilities and (9) 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 Supplement cash flow for the periods presented (in thousands): For the Three Months Ended March 31, 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 656 $ 1,882 Noncash investing activities: Increase in capital expenditures in accounts payables and accrued liabilities 25,528 6,535
New Accounting Standards	New Accounting Standards Improvements to Employee Share-Based Payment Accounting. In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involved several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. This new standard became effective for annual periods beginning after December 15, 2016. The Company adopted this guidance as of January 1, 2017 and it did not have a material impact on our consolidated financial statements. We elected to account for forfeitures on share-based payments by recognizing forfeitures of awards as they occur. 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 Accoun26

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Schedule of Supplemental Cash Flow Information	Supplement cash flow for the periods presented (in thousands): For the Three Months Ended March 31, 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 656 $ 1,882 Noncash investing activities: Increase in capital expenditures in accounts payables and accrued liabilities 25,528 6,535

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2017
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 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, 2017 2016 $ 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 as of the acquisition date after customary post-closing adjustments (in thousands). We allocated $162.9 million of the purchase price to unproved oil and natural gas properties Purchase Price Oil and natural gas properties $ 395,591 Other property and equipment 478 Accounts receivable 1,257 Accounts payable (1,816 ) Asset retirement obligations (3,101 ) Accrued liabilities (6,503 ) Total identifiable net assets $ 385,906
Summary of Unaudited Pro Forma Financial Information	The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2016 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Three Months Ended March 31, 2016 Revenues $ 35,334 Net income (loss) (14,229 ) Basic and diluted earnings per unit n/a

Fair Value Measurements of Fi28

Fair Value Measurements of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Fair Value Measurements at March 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 $ — $ 15,689 $ — $ 15,689 Liabilities: Commodity derivatives $ — $ 6,697 $ — $ 6,697 Fair Value Measurements at December 31, 2016 Using Quoted Prices in Active Market (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 7 $ — $ 7 Liabilities: Commodity derivatives $ — $ 22,185 $ — $ 22,185

Risk Management and Derivativ29

Risk Management and Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts	The following derivative contracts were in place at March 31, 2017: Remainder 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 6,346,000 11,565,800 9,877,900 Weighted-average fixed price $ 3.15 $ 3.03 $ 2.81 Collar contracts: Volume (MMBtu) 4,140,000 — — Weighted-average floor price $ 3.00 $ — $ — Weighted-average ceiling price $ 3.36 $ — $ — Put options: Volume (MMBtu) 3,095,895 — — Weighted-average floor price $ 3.40 $ — $ — Weighted-average put premium $ (0.37 ) $ — $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 1,526,900 1,638,500 1,381,300 Weighted-average fixed price $ 52.82 $ 53.68 $ 54.92 Collar contracts: Volume (Bbls) 43,872 25,096 — Weighted-average floor price $ 50.00 $ 50.00 $ — Weighted-average ceiling price $ 62.10 $ 62.10 $ — Put options: Volume (Bbls) 1,325,036 — — Weighted-average floor price $ 55.00 $ — $ — Weighted-average put premium $ (4.77 ) $ — $ —
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, 2017 and December 31, 2016. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives March 31, December 31, March 31, December 31, Type Balance Sheet Location 2017 2016 2017 2016 Commodity contracts Short-term derivative instruments $ 6,626 $ 4 $ 5,660 $ 14,091 Netting arrangements Short-term derivative instruments (952 ) (4 ) (952 ) (4 ) Net recorded fair value $ 5,674 $ — $ 4,708 $ 14,087 Commodity contacts Long-term derivative instruments $ 9,063 $ 3 $ 1,037 $ 8,094 Netting arrangements Long-term derivative instruments (670 ) (3 ) (670 ) (3 ) Net recorded fair value $ 8,393 $ — $ 367 $ 8,091
Schedule of Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the three months ending March 31, 2017 and 2016 (in thousands): Statements of For the Three Months Ended March 31, Operations Location 2017 2016 Commodity derivative contracts (Gain) $ (31,291 ) $ (3,246 )

Account Receivable (Tables)

Account Receivable (Tables)	3 Months Ended
	Mar. 31, 2017
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following (in thousands): March 31, December 31, 2017 2016 Oil, natural gas and NGL sales $ 17,309 $ 13,390 Joint interest billings 8,993 7,898 Severance tax 89 392 Other current receivables 755 4,848 Allowance for doubtful accounts (100 ) (100 ) Total $ 27,046 $ 26,428

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2017
Payables And Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consist of the following (in thousands): March 31, December 31, 2017 2016 Capital expenditures $ 43,462 $ 17,934 Deferred rent 392 386 Lease operating expense 2,565 2,608 General and administrative 2,849 1,471 Severance and ad valorem taxes 2,220 194 Interest expense 4,014 346 Other accrued liabilities 501 432 Total $ 56,003 $ 23,371

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2017 (in thousands): Asset retirement obligations at beginning of period $ 11,033 Accretion expense 150 Liabilities incurred 60 Revisions (285 ) Asset retirement obligations at end of period 10,958 Less: current portion (90 ) Asset retirement obligations – long-term $ 10,868

Long Term Debt (Tables)

Long Term Debt (Tables)	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Our debt obligations consisted of the following at the dates indicated (in thousands): For the Year Ended December 31, Credit Facility 2017 2016 WRD revolving credit facility $ — $ 242,750 6.875% senior unsecured notes, due February 2025 (1) 350,000 — Unamortized discounts (2,604 ) — Unamortized debt issuance costs - 6.875% senior unsecured notes (8,613 ) — Total long-term debt $ 338,783 $ 242,750 (1) The estimated fair value of this fixed-rate debt was $338.2 million at March 31, 2017. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
Schedule of Borrowing Base Credit Facility	The borrowing base for our credit facility was the following at the date indicated (in thousands): March 31, Credit Facility 2017 WRD revolving credit facility $ 362,500
Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: For the Three Months Ended March 31, Credit Facility 2017 2016 WRD revolving credit facility 3.52 % n/a WHR II revolving credit facility terminated December 2016 n/a 3.00 % Esquisto - revolving credit facility terminated December 2016 n/a 2.81 % Esquisto - revolving credit facility terminated January 2016 n/a 2.97 % Esquisto - Second lien terminated in January 2016 n/a 9.50 %
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, 2017 2016 WRD revolving credit facility (1) $ 2,479 $ 2,904 6.875% senior unsecured notes, due February 2025 8,613 n/a Total $ 11,092 $ 2,904 (1) We classified $0.5 million and $0.6 million of unamortized deferred financing costs at March 31, 2017 and December 31, 2016, respectively, under current assets as a component of “prepaid expenses and other current assets.”

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Summary of Changes in Common Shares Issued	The following is a summary of the changes in our common shares issued for the three months ended March 31, 2017: Balance, December 31, 2016 91,680,441 Common stock issued 2,297,100 Restricted common stock issued 10,000 Balance, March 31, 2017 93,987,541

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Schedule of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of earnings (loss) per share, or EPS, for the three months ending March 31, 2017 (in thousands, except per share amounts): Numerator: Net income (loss) available to WildHorse Resources $ 20,252 Denominator: Weighted-average common shares outstanding (in thousands) (1) 93,216 Basic EPS $ 0.22 Diluted EPS (1) $ 0.22 (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for the three months ended March 31, 2017. For the three months ended March 31, 2017, 6 incremental shares were included in the calculation of diluted EPS under the treasury stock method.

Long Term Incentive Plans (Tabl

Long Term Incentive Plans (Tables)	3 Months Ended
	Mar. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Restricted Common Stock Awards Granted Under 2016 LTIP	The following table summarizes information regarding restricted common 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, 2016 353,334 $ 14.50 Granted (2) 10,000 $ 14.22 Restricted common stock outstanding at March 31, 2017 363,334 $ 14.49 (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 2017 was $0.1 million based on grant date market price of $14.22 per share.

Incentive Units (Tables)

Incentive Units (Tables)	3 Months Ended
	Mar. 31, 2017
Compensation Related Costs [Abstract]
Schedule of Key Assumptions Used to Estimate Fair Value of Incentive Units	The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following key assumptions: Incentive Unit Valuation As Of March 31, 2017 Expected life (years) 1.29 - 5.54 Expected volatility (range) 57.0% - 64.0% Dividend yield 0.0% Risk-free rate (range) 1.09% - 1.99%

Segment Reporting (Tables)

Segment Reporting (Tables)	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Reconciliation of Net Income (Loss) to Adjusted EBITDAX	The following table presents a reconciliation of net income (loss) to Adjusted EBITDAX (in thousands): For the Three Months Ended March 31, 2017 2016 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 20,252 $ (14,216 ) Interest expense, net 5,571 1,972 Income tax (benefit) expense 11,700 139 Depreciation, depletion and amortization 26,443 22,063 Exploration expense 1,615 7,443 (Gain) loss on derivative instruments (31,291 ) (3,246 ) Cash settlements received (paid) on derivative instruments (983 ) 3,373 Stock-based compensation 495 — Acquisition related costs 599 — Debt extinguishment costs (11 ) 358 Public offering costs 182 — Non-cash liability amortization — (183 ) Total Adjusted EBITDAX $ 34,572 $ 17,703

Organization and Basis of Pre39

Organization and Basis of Presentation - Additional Information (Details)	Mar. 31, 2017Subsidiary
WHR II
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries	2
Esquisto
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries	2

Summary of Significant Accoun40

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 656	$ 1,882
Noncash investing activities:
Increase in capital expenditures in accounts payables and accrued liabilities	$ 25,528	$ 6,535

Acquisitions and Divestitures -

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

Acquisitions and Divestitures42

Acquisitions and Divestitures - Additional Information (Details) $ in Thousands	Feb. 02, 2017USD ($)Transaction	Dec. 19, 2016USD ($)a	Mar. 31, 2017USD ($)
Business Acquisition [Line Items]
Business acquisition, post-closing receipt			$ 3,905
Third Parties Acquisition
Business Acquisition [Line Items]
Number of transactions closed as part of acquisition of oil and natural gas producing and non-producing properties | Transaction	1
Payments to acquire oil and natural gas properties	$ 2,400
Purchase price allocated to unproved oil and natural gas properties	$ 2,300
Burleson North Acquisition
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties		$ 389,800
Purchase price allocated to unproved oil and natural gas properties		$ 162,900
Area of oil and natural gas properties acquired | a		158,000
Business acquisition, post-closing receipt			$ 3,900

Acquisitions and Divestitures43

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Details) - Burleson North Acquisition $ in Thousands	Dec. 19, 2016USD ($)
Business Acquisition [Line Items]
Oil and natural gas properties, Purchase Price	$ 395,591
Other property and equipment, Purchase Price	478
Accounts receivable, Purchase Price	1,257
Accounts payable, Purchase Price	(1,816)
Asset retirement obligations, Purchase Price	(3,101)
Accrued liabilities, Purchase Price	(6,503)
Total identifiable net assets, Purchase Price	$ 385,906

Acquisitions and Divestitures44

Acquisitions and Divestitures - Summary of Unaudited Pro Forma Financial Information (Details) - Burleson North Acquisition $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)
Business Acquisition [Line Items]
Revenues	$ 35,334
Net income (loss)	$ (14,229)

Fair Value Measurements of Fi45

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value Measurements Recurring - Commodity Derivatives - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Assets:
Fair value of derivative asset	$ 15,689	$ 7
Liabilities:
Fair value of derivative liability	6,697	22,185
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	15,689	7
Liabilities:
Fair value of derivative liability	$ 6,697	$ 22,185

Fair Value Measurements of Fi46

Fair Value Measurements of Financial Instruments - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Impairment of proved oil and natural gas properties	$ 0	$ 0
Impairments of unproved properties	$ 683,000

Risk Management and Derivativ47

Risk Management and Derivative Instruments - Additional Information (Details)	Mar. 31, 2017USD ($)
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Deferred premiums	$ 100,000
Cash collateral received or pledged	$ 0

Risk Management and Derivativ48

Risk Management and Derivative Instruments - Schedule of Derivative Contracts (Details)	3 Months Ended
	Mar. 31, 2017MMBTU$ / MMBTU$ / bblbbl
Natural Gas Derivative Contracts Fixed Price Swap Remainder 2017
Derivative [Line Items]
Volume (MMBtu) | MMBTU	6,346,000
Weighted-average fixed price | $ / MMBTU	3.15
Natural Gas Derivative Contracts Collar Remainder 2017
Derivative [Line Items]
Volume (MMBtu) | MMBTU	4,140,000
Weighted-average floor price | $ / MMBTU	3
Weighted-average ceiling price | $ / MMBTU	3.36
Natural Gas Derivative Contracts Put Options Remainder 2017
Derivative [Line Items]
Volume (MMBtu) | MMBTU	3,095,895
Weighted-average floor price | $ / MMBTU	3.40
Weighted-average put premium | $ / MMBTU	(0.37)
Crude Oil Derivative Contracts Fixed Price Swap Remainder 2017
Derivative [Line Items]
Volume (Bbls) | bbl	1,526,900
Weighted-average fixed price	52.82
Crude Oil Derivative Contracts Collar Remainder 2017
Derivative [Line Items]
Weighted-average floor price	50
Weighted-average ceiling price	62.10
Volume (Bbls) | bbl	43,872
Crude Oil Derivative Contracts Put Options Remainder 2017
Derivative [Line Items]
Weighted-average floor price	55
Weighted-average put premium	(4.77)
Volume (Bbls) | bbl	1,325,036
Natural Gas Derivative Contracts Fixed Price Swap 2018
Derivative [Line Items]
Volume (MMBtu) | MMBTU	11,565,800
Weighted-average fixed price | $ / MMBTU	3.03
Crude Oil Derivative Contracts Fixed Price Swap 2018
Derivative [Line Items]
Volume (Bbls) | bbl	1,638,500
Weighted-average fixed price	53.68
Crude Oil Derivative Contracts Collar 2018
Derivative [Line Items]
Weighted-average floor price	50
Weighted-average ceiling price	62.10
Volume (Bbls) | bbl	25,096
Natural Gas Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (MMBtu) | MMBTU	9,877,900
Weighted-average fixed price | $ / MMBTU	2.81
Crude Oil Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (Bbls) | bbl	1,381,300
Weighted-average fixed price	54.92

Risk Management and Derivativ49

Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Details) - Commodity Derivative Contracts - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Short-term Derivative Instruments
Derivative [Line Items]
Asset Derivatives, Gross fair value	$ 6,626	$ 4
Asset Derivatives, Netting arrangements	(952)	(4)
Asset Derivatives, Net recorded fair value	5,674
Liability Derivatives, Gross fair value	5,660	14,091
Liability Derivatives, Netting arrangements	(952)	(4)
Liability Derivatives, Net recorded fair value	4,708	14,087
Long-term Derivative Instruments
Derivative [Line Items]
Asset Derivatives, Gross fair value	9,063	3
Asset Derivatives, Netting arrangements	(670)	(3)
Asset Derivatives, Net recorded fair value	8,393
Liability Derivatives, Gross fair value	1,037	8,094
Liability Derivatives, Netting arrangements	(670)	(3)
Liability Derivatives, Net recorded fair value	$ 367	$ 8,091

Risk Management and Derivativ50

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivatives	$ (31,291)	$ (3,246)
Commodity Derivative Contracts
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivatives	$ (31,291)	$ (3,246)

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 17,309	$ 13,390
Joint interest billings	8,993	7,898
Severance tax	89	392
Other current receivables	755	4,848
Allowance for doubtful accounts	(100)	(100)
Total	$ 27,046	$ 26,428

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Capital expenditures	$ 43,462	$ 17,934
Deferred rent	392	386
Lease operating expense	2,565	2,608
General and administrative	2,849	1,471
Severance and ad valorem taxes	2,220	194
Interest expense	4,014	346
Other accrued liabilities	501	432
Total	$ 56,003	$ 23,371

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 11,033
Accretion of asset retirement obligations	150	$ 98
Liabilities incurred	60
Revisions	(285)
Asset retirement obligations at end of period	10,958
Less: current portion	(90)		$ (90)
Asset retirement obligations	$ 10,868		$ 10,943

Long Term Debt - Schedule of De

Long Term Debt - Schedule of Debt Obligations (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Unamortized discounts	$ 2,604
Unamortized debt issuance costs	11,092	$ 2,904
Total long-term debt	338,783	242,750
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Long-term debt, gross	350,000
Unamortized debt issuance costs	8,613
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross		242,750
Unamortized debt issuance costs	$ 2,479	$ 2,904

Long Term Debt - Schedule of 55

Long Term Debt - Schedule of Debt Obligations (Parenthetical) (Details) - 6.875% Senior Unsecured Notes, Due February 2025 $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Debt Instrument [Line Items]
Debt instrument interest rate percentage	6.875%
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	$ 338.2

Long Term Debt - Schedule of Bo

Long Term Debt - Schedule of Borrowing Base Credit Facility (Details) $ in Thousands	Mar. 31, 2017USD ($)
Revolving Credit Facility
Line Of Credit Facility [Line Items]
WRD revolving credit facility	$ 362,500

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Details) - USD ($) $ in Thousands	Feb. 01, 2017	Mar. 31, 2017	Apr. 27, 2017	Apr. 04, 2017
Debt Instrument [Line Items]
Proceeds from senior notes offering		$ 347,354
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Debt instrument interest rate percentage		6.875%
Debt instrument maturity date		Feb. 1, 2025
6.875% Senior Unsecured Notes, Due February 2025 | Private Placement
Debt Instrument [Line Items]
Aggregate principal amount	$ 350,000
Debt instrument interest rate percentage	6.875%
Issue price of notes as a percentage of par value	99.244%
Proceeds from senior notes offering	$ 338,600
Debt instrument maturity date		Feb. 1, 2025
Reduction in borrowing base	$ 87,500
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 that 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 | Private Placement | Maximum
Debt Instrument [Line Items]
Debt instrument redemption percentage of principal amount	35.00%
Revolving Credit Facility
Debt Instrument [Line Items]
WRD revolving credit facility		$ 362,500
Subsequent Event | Revolving Credit Facility
Debt Instrument [Line Items]
WRD revolving credit facility				$ 450,000
Subsequent Event | Revolving Credit Facility | Standby Letter of Credit | Railroad Commission of Texas
Debt Instrument [Line Items]
Letters of Credit Outstanding			$ 1,900

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Details)	Mar. 31, 2017	Mar. 31, 2016
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	3.52%
WHR II Revolving Credit Facility Terminated December 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.00%
Esquisto - Revolving Credit Facility Terminated December 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.81%
Esquisto - Revolving Credit Facility Terminated January 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.97%
Esquisto - Second Lien Terminated In January 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		9.50%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 11,092	$ 2,904
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Unamortized deferred financing costs	8,613
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 2,479	$ 2,904

Long Term Debt - Summary of U60

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 11,092	$ 2,904
Prepaid Expenses and Other Current Assets
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 500	$ 600

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 17, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Class Of Stock [Line Items]
Common stock, shares authorized		500,000,000		500,000,000
Common stock, par value		$ 0.01		$ 0.01
Common stock offering price	$ 15
Proceeds from exercise of over-allotment	$ 32,600
Capital contributions received from members			$ 12,776
Common Stock
Class Of Stock [Line Items]
Common stock issued	2,297,100	2,297,100

Equity - Summary of Changes in

Equity - Summary of Changes in Common Shares Issued (Details) - Common Stock - shares	Jan. 17, 2017	Mar. 31, 2017
Class Of Stock [Line Items]
Balance, December 31, 2016		91,680,441
Common stock issued	2,297,100	2,297,100
Restricted common stock issued		10,000
Balance, March 31, 2017		93,987,541

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Details) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)$ / sharesshares
Numerator:
Net income (loss) available to WildHorse Resources | $	$ 20,252
Denominator:
Weighted-average common shares outstanding | shares	93,216
Basic	$ 0.22
Diluted	$ 0.22

Earnings Per Share - Schedule64

Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Parenthetical) (Details) shares in Thousands	3 Months Ended
	Mar. 31, 2017shares
Earnings Per Share [Abstract]
Incremental shares included in calculation of diluted EPS	6

Long Term Incentive Plans - Add

Long Term Incentive Plans - Additional Information (Details) - 2016 Long-Term Incentive Plan $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock authorized for issuance under plan | shares	9,512,500
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized compensation expense	$ 0.5
Unrecognized compensation cost	$ 4.7
Unrecognized compensation cost, weighted-average period	2 years 6 months 29 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, 2017$ / sharesshares
Number of Shares
Restricted common stock outstanding at December 31, 2016 | shares	353,334
Restricted commons shares, Granted | shares	10,000
Restricted common stock outstanding at March 31, 2017 | shares	363,334
Weighted Average Grant Date Fair Value per Share
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share at December 31, 2016 | $ / shares	$ 14.50
Restricted common shares, Granted, Weighted-Average Grant Date Fair Value per Share | $ / shares	14.22
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share at March 31, 2017 | $ / shares	$ 14.49

Long Term Incentive Plans - S67

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, 2017USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value | $	$ 0.1
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price | $ / shares	$ 14.22

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) - Incentive Unit Valuation Tranche One	3 Months Ended
	Mar. 31, 2017USD ($)
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Recognized compensation expense	$ 0
Unrecognized compensation costs associated with incentive units	$ 27,600,000

Incentive Units - Schedule of K

Incentive Units - Schedule of Key Assumptions Used to Estimate Fair Value of Incentive Units (Details) - Incentive Unit Valuation Tranche One	3 Months Ended
	Mar. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Dividend yield	0.00%
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected life (years)	1 year 3 months 15 days
Expected volatility (range)	57.00%
Risk-free rate (range)	1.09%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected life (years)	5 years 6 months 15 days
Expected volatility (range)	64.00%
Risk-free rate (range)	1.99%

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
General and Administrative | Esquisto
Related Party Transaction [Line Items]
Notes payable to related party		$ 1,000,000
Drilling and Producing Wells | Esquisto
Related Party Transaction [Line Items]
Payment made to related party		300,000
Genesis Energy Partners, L.P
Related Party Transaction [Line Items]
Proceeds from sale of hydrocarbons and other liquids	$ 900,000
Highmark Energy Operating, LLC | Non-operated Working Interests in Oil and Natural Gas Properties
Related Party Transaction [Line Items]
Net payments received from related parties		200,000
Highmark Energy Operating, LLC | Non-operated Working Interests in Oil and Natural Gas Properties | Maximum
Related Party Transaction [Line Items]
Net payments received from related parties	100,000
Cretic Energy Services, LLC | Drilling and Completion Activities
Related Party Transaction [Line Items]
Payment made to related party		100,000
Related party payments or receipts	0
PennTex Midstream Partners, LP | Gathering, Processing and Transportation of Natural Gas and NGLs | Maximum
Related Party Transaction [Line Items]
Net payment made to related party		100,000
WildHorse Resources, LLC | Non-operated Working Interests in Oil and Natural Gas Properties | Maximum
Related Party Transaction [Line Items]
Payment made to related party		100,000
NGP X US Holdings LP | Maximum
Related Party Transaction [Line Items]
Directors fees		100,000
CH4 Energy
Related Party Transaction [Line Items]
Net payments received from related parties	$ 300,000
Related party payments or receipts		0
WHR II | Promissory Notes
Related Party Transaction [Line Items]
Debt instrument interest rate percentage	2.50%
Debt instrument, interest payments		0
Calbri Energy, Inc. | Completion Consulting Services | Esquisto
Related Party Transaction [Line Items]
Payment made to related party		$ 100,000
Calbri Energy, Inc. | Completion Consulting Services | Maximum | Esquisto
Related Party Transaction [Line Items]
Percentage of ownership		1.00%
Petromax Operating Company, Inc. | Chief Operating Officer of Esquisto
Related Party Transaction [Line Items]
Percentage of ownership	33.30%
Service Providers | Esquisto
Related Party Transaction [Line Items]
Payment made to related party	$ 100,000

Segment Disclosures - Additiona

Segment Disclosures - Additional Information (Details)	3 Months Ended
	Mar. 31, 2017Segment
Segment Reporting [Abstract]
Number of operating segments	2
Number of reportable segments	1

Segment Disclosures - Reconcili

Segment Disclosures - Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$ 20,252	$ (14,216)
Interest expense, net	5,571	1,972
Income tax (benefit) expense	11,700	139
Depreciation, depletion and amortization	26,443	22,063
Exploration expense	1,615	7,443
(Gain) loss on commodity derivatives	(31,291)	(3,246)
Cash settlements received (paid) on derivative instruments	(983)	3,373
Stock-based compensation	495
Acquisition-related costs	599
Debt extinguishment costs	(11)	358
Public offering costs	182
Non-cash liability amortization		(183)
Total Adjusted EBITDAX	$ 34,572	$ 17,703

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income tax (benefit) expense	$ 11,700,000	$ 139,000
Effective tax rate	36.60%	(1.00%)
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, 2017USD ($)Stageacre ft	Dec. 31, 2016USD ($)
Commitments And Contingencies [Line Items]
Accrued liability for existing and potential claims	$ 0	$ 0
Environmental obligations recognized	0	0
Restricted cash	$ 752,000	886,000
Interruptible water availability agreement, start date	Feb. 1, 2017
Interruptible water availability agreement, end date	Dec. 31, 2021
Dedicated Fracturing Fleet Services Agreement
Commitments And Contingencies [Line Items]
Term of agreement for completion of wells and drilling operations	20 months
Additional term of agreement for completion of wells and drilling operations	12 months
Fixed monthly service fee for cost of equipment and personnel	$ 2,700,000
Additional payment to be paid on achievement certain mile stones	$ 6,000
Minimum number of stages to be completed for milestone payments | Stage	360
Percentage of amount payable in excess of chemicals and fuel cost	10.00%
Early termination fee, description	approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on the termination date.
Early termination fee, approximate multiplier to number of months remaining under initial contract term	$ 1,400,000
Interruptible Water Availability Agreement
Commitments And Contingencies [Line Items]
Aggregate of acre-feet of water per year | acre ft	6,978
Agreement payment	$ 400,000
Certificates of Deposits
Commitments And Contingencies [Line Items]
Restricted cash	$ 752,000	$ 886,000

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) $ / shares in Units, $ in Millions	May 10, 2017USD ($)aDirector$ / sharesshares	Apr. 30, 2017USD ($)	Mar. 31, 2017$ / shares	Dec. 31, 2016$ / shares
Subsequent Event [Line Items]
Preferred stock, par value			$ 0.01	$ 0.01
Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement
Subsequent Event [Line Items]
Date of agreement			May 10, 2017
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement
Subsequent Event [Line Items]
Preferred stock to be issued | shares	435,000
Preferred stock, par value	$ 0.01
Preferred stock, liquidation preference	$ 1,000
Preferred stock, dividend rate percentage	6.00%
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | 30-Month Anniversary
Subsequent Event [Line Items]
Convertible preferred stock, terms of conversion	The Preferred Stock will also participate in dividends and distributions on our common stock on an as-converted basis. If at any time following the 30-month anniversary of the issuance date the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | First Anniversary
Subsequent Event [Line Items]
Conversion of stock, conversion price	$ 13.90
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | Fourth Anniversary
Subsequent Event [Line Items]
Convertible preferred stock, terms of conversion	the Company may cause the conversion of the Preferred Stock at the Conversion Rate, provided the closing sale price of the common stock equals or exceeds 140% of the Conversion Price for the 20 trading days ending on and including the date of delivery of the Company’s notice to convert and subject to certain other requirements regarding registration of the shares issuable upon conversion. Notwithstanding the foregoing, the Company shall only be permitted to deliver one conversion notice during any 180 day period and the number of shares of common stock issued upon conversion of the Preferred Stock for which such automatic conversion notice is given shall be limited to 25 times the average daily trading volume of our common stock during the 20 trading days ending on and including the date of delivery of the Company’s notice to convert.
Number of trading days required for conversion	20 days
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | Sixth Anniversary
Subsequent Event [Line Items]
Multiple percentage on preferred stock liquidation preference	112.00%
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | Seventh Anniversary
Subsequent Event [Line Items]
Multiple percentage on preferred stock liquidation preference	109.00%
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | After Seventh Anniversary
Subsequent Event [Line Items]
Multiple percentage on preferred stock liquidation preference	106.00%
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | Minimum | 30-Month Anniversary
Subsequent Event [Line Items]
Percentage of preferred stock conversion price	130.00%
Number of trading days required for conversion	25 days
Subsequent Event | Series A Perpetual Convertible Preferred Stock | Preferred Stock Purchase Agreement | Minimum | Fourth Anniversary
Subsequent Event [Line Items]
Percentage of preferred stock conversion price	140.00%
Subsequent Event | 10% Ownership of Outstanding Common Stock | Carlyle
Subsequent Event [Line Items]
Number of directors entitled to be elected upon holding of outstanding common stock | Director	2
Holding percentage of outstanding common stock to elect director	10.00%
Subsequent Event | 5% Ownership of Outstanding Common Stock | Carlyle
Subsequent Event [Line Items]
Number of directors entitled to be elected upon holding of outstanding common stock | Director	1
Holding percentage of outstanding common stock to elect director	5.00%
APC/KKR Acquisitions
Subsequent Event [Line Items]
Business acquisition, date of acquisition			May 10, 2017
Business acquisition, expected closing date of acquisition			Jun. 30, 2017
Business acquisition, effective date of acquisition			Jan. 1, 2017
APC/KKR Acquisitions | Subsequent Event
Subsequent Event [Line Items]
Pending business acquisition, aggregate net acres to be acquired | a	111,000
APC Subs | Subsequent Event
Subsequent Event [Line Items]
Pending business acquisition, aggregate purchase price | $	$ 556
KKR | Subsequent Event | Common Stock
Subsequent Event [Line Items]
Business acquisition, aggregate purchase price, shares issued | shares	6,300,000
Business acquisition, aggregate purchase price, value of shares issued | $	$ 69
Eagle Ford Acquisitions | Subsequent Event | Burleson County, TX
Subsequent Event [Line Items]
Aggregate price to acquire oil and gas properties | $		$ 13.2