Oakfield Energy S-4 29 Sep 17 Registration of securities issued in business combination transactions Financial data

Document and Entity Information

Document and Entity Information	6 Months Ended
	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	S4
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Trading Symbol	WRD
Entity Registrant Name	WildHorse Resource Development Corporation
Entity Central Index Key	1,681,714
Entity Filer Category	Non-accelerated Filer

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 14,633	$ 3,115	$ 43,126
Accounts receivable, net	41,997	26,428	13,737
Short-term derivative instruments	28,192		7,076
Prepaid expenses and other current assets	3,695	1,633	2,830
Total current assets	88,517	31,176	66,769
Property and equipment:
Oil and gas properties	2,475,082	1,573,848	983,972
Other property and equipment	41,320	34,344	30,609
Accumulated depreciation, depletion and amortization	(259,636)	(200,293)	(118,943)
Total property and equipment, net	2,256,766	1,407,899	895,638
Other noncurrent assets:
Restricted cash	752	886	551
Long-term derivative instruments	24,435		2,440
Debt issuance costs	3,080	2,320	967
Total assets	2,373,550	1,442,281	966,365
Current liabilities:
Accounts payable	25,176	21,014	34,843
Accrued liabilities	125,746	23,371	28,782
Short-term derivative instruments	822	14,087
Asset retirement obligations	90	90	90
Total current liabilities	151,834	58,562	63,715
Noncurrent liabilities:
Long-term debt	485,033	242,750	237,857
Asset retirement obligations	13,661	10,943	6,930
Notes payable to members (Note 14)			6,438
Deferred tax liabilities	139,445	112,552	852
Long-term derivative instruments	49	8,091
Other noncurrent liabilities	1,296	1,495	1,884
Total noncurrent liabilities	639,484	375,831	253,961
Total liabilities	791,318	434,393	317,676
Commitments and contingencies
Series A perpetual convertible preferred stock, $0.01 par value: 50,000,000 shares authorized; 435,000 shares issued and outstanding at June 30, 2017	432,657
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; 101,136,017 shares and 91,680,441 shares issued and outstanding at June 30, 2017 and December 31, 2016, respectively	1,011	917
Additional paid-in capital	1,112,416	1,017,368
Accumulated earnings (deficit)	36,148	(10,397)
Total stockholders' equity	1,149,575	1,007,888	648,689
Predecessor			274,133
Previous owner			374,556
Total liabilities and equity	$ 2,373,550	$ 1,442,281	$ 966,365

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Jun. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred stock, par value		$ 0.01
Convertible preferred stock, par value	$ 0.01
Preferred stock, shares authorized		50,000,000
Convertible preferred stock, shares authorized	50,000,000
Preferred Stock, Shares Issued		0
Convertible preferred stock, shares issued	435,000
Preferred stock, shares outstanding		0
Convertible preferred stock, shares outstanding	435,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	101,136,017	91,680,441
Common stock, shares outstanding	101,136,017	91,680,441

STATEMENTS OF CONDENSED CONSOLI

STATEMENTS OF CONDENSED CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil sales	$ 52,963	$ 18,683	$ 92,040	$ 31,936	$ 75,938	$ 42,971	$ 2,780
Natural gas sales	13,277	9,233	25,422	19,439	43,487	38,665	41,694
NGL sales	3,404	1,225	6,067	2,170	5,786	4,295	989
Other income	529	574	936	1,297	2,131	404
Total operating revenues	70,173	29,715	124,465	54,842	127,342	86,335	45,463
Operating expenses:
Lease operating expenses	6,837	2,302	13,765	5,062	12,320	14,053	9,428
Gathering, processing and transportation	1,942	1,583	3,642	3,474	6,581	5,300	3,953
Gathering system operating expense	25	64	44	118	99	914
Taxes other than income tax	4,509	1,785	8,408	3,257	6,814	5,510	2,584
Cost of oil sales							687
Depreciation, depletion and amortization	33,229	19,923	59,672	41,986	81,757	56,244	15,297
Impairment of proved oil and gas properties						9,312	24,721
General and administrative	10,049	4,683	17,531	9,132	23,973	15,903	5,838
Exploration expense	11,504	80	13,119	7,523	12,026	18,299	1,597
Total operating expense	68,095	30,420	116,181	70,552	143,570	125,535	64,105
Income (loss) from operations	2,078	(705)	8,284	(15,710)	(16,228)	(39,200)	(18,642)
Other income (expense):
Interest expense, net	(6,633)	(1,781)	(12,204)	(3,753)	(7,834)	(6,943)	(2,680)
Debt extinguishment costs			11	(358)	(1,667)
Gain (loss) on derivative instruments	46,116	(15,610)	77,407	(12,364)	(26,771)	13,854	6,514
Other income (expense)	(2)	(74)	13	(62)	(151)	(147)	213
Total other income (expense)	39,481	(17,465)	65,227	(16,537)	(36,423)	6,764	4,047
Income (loss) before income taxes	41,559	(18,170)	73,511	(32,247)	(52,651)	(32,436)	(14,595)
Income tax benefit (expense)	(15,193)	(111)	(26,893)	(250)	5,575	(604)	158
Net income (loss)	26,366	(18,281)	46,618	(32,497)	(47,076)	(33,040)	(14,437)
Net income (loss) attributable to previous owners		(5,265)		(7,782)	(2,681)	(3,085)
Net income (loss) attributable to predecessor		$ (13,016)		$ (24,715)	(33,998)	$ (29,955)	$ (14,437)
Net income (loss) available to WildHorse Development	26,366		46,618		(10,397)
Preferred stock dividends	73		73
Undistributed earnings allocated to participating securities	387		434
Net income (loss) available to common stockholders	$ 25,906		$ 46,111		$ (10,397)
Earnings per common share:
Basic	$ 0.28		$ 0.49		$ (0.11)
Diluted	$ 0.28		$ 0.49		$ (0.11)
Weighted-average common shares outstanding:
Basic	93,685		93,452		91,327
Diluted	93,685		93,452		91,327

STATEMENTS OF CONDENSED CONSOL5

STATEMENTS OF CONDENSED CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ 46,618	$ (32,497)	$ (47,076)	$ (33,040)	$ (14,437)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	59,367	41,788	81,350	55,890	14,988
Accretion of asset retirement obligations	305	198	407	354	309
Impairment of proved oil and gas properties				9,312	24,721
Dry hole expense and impairments of unproved properties	10,663	62	3,051	11,780	208
Amortization of debt issuance cost	1,277	228	479	711
(Gain) loss on derivative instruments	(77,407)	12,364	26,771	(13,854)	(6,514)
Cash settlements on derivative instruments	1,093	5,898	4,975	11,517	(2,712)
Accretion of senior note discount	105
Deferred income tax expense (benefit)	26,893	230	(5,575)	604	(189)
Debt extinguishment expense	(11)	358	1,667
Amortization of equity awards	1,803		68
Gain (loss) on sale of properties			43
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	(22,307)	(3,876)	(16,300)	15,421	(19,416)
Decrease (increase) in prepaid expenses			(448)	165	(336)
Decrease (increase) in prepaid expenses and other current assets	(1,760)	2,390
Decrease (increase) in inventories				108	450
(Decrease) increase in accounts payable and accrued liabilities	25,395	(9,830)	(27,150)	(8,872)	28,588
Net cash flow provided by operating activities	72,034	17,313	22,262	50,096	25,660
Cash flows from investing activities:
Acquisitions of oil and gas properties	(547,389)	(4,228)	(436,072)	(165,836)
Additions to oil and gas properties	(211,264)	(73,375)	(125,837)	(253,922)	(128,667)
Additions to and acquisitions of other property and equipment	(6,189)	(2,827)	(5,403)	(23,653)	(300)
Sales of other property and equipment			102	22
Change in restricted cash	135	(86)	(335)	(250)
Net cash used in investing activities	(764,707)	(80,516)	(567,545)	(443,639)	(128,967)
Cash flows from financing activities:
Advances on revolving credit facilities	161,500	89,000	383,450	153,400	67,400
Payments on revolving credit facilities	(258,250)	(101,000)	(378,700)	(63,500)	(50,300)
Debt issuance cost	(10,756)	(480)	(3,607)	(875)	(57)
Termination of second lien		(225)	(225)
Proceeds from initial public offering			412,500
Proceeds from senior notes offering	347,354
Proceeds from the issuance of preferred stock	435,000
Predecessor contributions		13,280	13,280	125,098	97,546
Proceeds from the issuance of common stock	34,457
Previous owner contributions		25,000	97,000	208,376
Contributions from previous owners at inception of common control				1,982
Net cash provided by financing activities	704,191	25,575	505,272	424,481	114,589
Net change in cash and cash equivalents	11,518	(37,628)	(40,011)	30,938	11,282
Cash and cash equivalents, beginning of period	3,115	43,126	43,126	12,188	906
Cash and cash equivalents, end of period	14,633	$ 5,498	3,115	$ 43,126	$ 12,188
Initial Public Offering
Cash flows from financing activities:
Cost incurred in conjunction with stock issuance	(601)		$ (18,426)
Common Stock
Cash flows from financing activities:
Cost incurred in conjunction with stock issuance	(2,097)
Preferred Shares
Cash flows from financing activities:
Cost incurred in conjunction with stock issuance	$ (2,416)

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid in Capital	Accumulated Earnings (Deficit)
Beginning Balance (Predecessor) at Dec. 31, 2013	$ 95,882
Beginning Balance at Dec. 31, 2013	95,882
Capital contributions | Predecessor	89,437
Capital contributions	89,437
Notes receivable from members | Predecessor	8,109
Notes receivable from members	8,109
Net income (loss) | Predecessor	(14,437)
Net income (loss)	(14,437)
Ending Balance (Predecessor) at Dec. 31, 2014	178,991
Ending Balance at Dec. 31, 2014	178,991
Balance at inception of common control (February 17, 2015) | Previous Owner	86,478
Balance at inception of common control (February 17, 2015)	86,478
Capital contributions | Predecessor	125,850
Capital contributions | Previous Owner	208,376
Capital contributions	334,226
Property contributions | Previous Owner	40,116
Property contributions	40,116
Common control step up in basis | Previous Owner	42,671
Common control step up in basis	42,671
Notes receivable from members | Predecessor	(753)
Notes receivable from members	(753)
Net income (loss) | Predecessor	(29,955)
Net income (loss) | Previous Owner	(3,085)
Net income (loss)	(33,040)
Ending Balance (Predecessor) at Dec. 31, 2015	274,133
Ending Balance (Previous Owner) at Dec. 31, 2015	374,556
Ending Balance at Dec. 31, 2015	648,689
Capital contributions | Predecessor	10,837
Capital contributions | Previous Owner	97,000
Capital contributions	107,837
Property contributions | Previous Owner	329
Property contributions	329
Notes receivable from members | Predecessor	(132)
Notes receivable from members	(132)
Net income (loss) | Predecessor	(33,998)
Net income (loss) | Previous Owner	(2,681)
Net income (loss)	(47,076)			$ (10,397)
Issuance of common stock	412,500	$ 275	$ 412,225
Costs incurred in connection with initial public offering	(19,252)		(19,252)
Issuance of common stock in connection with the Acquisition	19,626	13	19,613
Dissolution of notes receivable from members | Predecessor	2,575
Dissolution of notes receivable from members	2,575
Amortization of equity awards	68	4	64
Issuance of shares in connection with Corporate Reorganization | Predecessor	(253,415)
Issuance of shares in connection with Corporate Reorganization | Previous Owner	(469,204)
Issuance of shares in connection with Corporate Reorganization		625	721,994
Tax related effects in connection with Corporate Reorganization and initial public offering	(117,276)		(117,276)
Ending Balance at Dec. 31, 2016	1,007,888	917	1,017,368	(10,397)
Net income (loss)	46,618			46,618
Issuance of common stock	34,457	23	34,434
Costs incurred in connection with initial public offering	(1,872)		(1,872)
Issuance of common stock in connection with the Acquisition	60,754	55	60,699
Accrual of preferred stock paid-in-kind dividend	(73)			(73)
Amortization of equity awards	1,803	16	1,787
Ending Balance at Jun. 30, 2017	$ 1,149,575	$ 1,011	$ 1,112,416	$ 36,148

Organization and Basis of Prese

Organization and Basis of Presentation	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation WildHorse Resource Development Corporation is a publicly traded Delaware corporation, the common stock of which are listed on the New York Stock Exchange (“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 in the United States of America. 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. In May 2017, in connection with the Acquisition, WRD formed WHR Eagle Ford LLC (“WHR EF”) as a wholly owned subsidiary. 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 and six months ended June 30, 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) incentive unit compensation cost; (9) contingent liabilities and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.	Note 1. Organization and Basis of Presentation WildHorse Resource Development Corporation (the “Company”) 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. 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 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). Reference “WildHorse Investment Holdings” refers to WildHorse Investment Holdings, LLC. Reference to “Previous owner” refers to both Esquisto and Acquisition Co.. Reference to “Esquisto Investment Holdings” refers to Esquisto Investment Holdings, LLC. Reference to “WildHorse Holdings” refers to WHR Holdings, LLC. Reference to “Esquisto Holdings” refers to Esquisto Holdings, LLC. Reference to “Acquisition Co. Holdings” refers to WHE AcqCo Holdings, LLC. Reference to “NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in WHR II, Esquisto and Acquisition Co. The Company was formed in August 2016 to serve as a holding company for the assets of WHR II and Esquisto. We did not have any operations until we completed our initial public offering on December 19, 2016. In connection with our initial public offering and Corporate Reorganization (defined below), our accounting predecessor, WHR II was contributed to us. In addition to WHR II, we received Esquisto and Acquisition Co. We are an independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Initial Public Offering and Corporate Reorganization The Company issued and sold to the public in its initial public offering 27,500,000 shares of common stock. The gross proceeds from the sale of the common stock were $412.5 million, net of underwriting discounts of $14.1 million and other offering costs of $5.0 million. The net proceeds from our initial public offering were $393.4 million. Debt issuance costs of $2.9 million related to the establishment of the Company’s revolving credit facility were also incurred in conjunction with our initial public offering. Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation. 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 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 (i) (a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (ii) (a) for the period from January 1, 2015 to February 16, 2015 and (b) for the year ended December 31, 2014, have been derived from the results attributable to our predecessor. Furthermore, the results of Acquisition Co. are reflected in the financial statements presented herein beginning on December 19, 2016. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. 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 to other income. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 Six Months Ended June 30, 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 306 $ 3,671 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities 82,295 (5,321 ) New Accounting Standards Improvements to Employee Share-Based Payment Accounting. Leases. right-of-use Revenue from Contracts with Customers. 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.	Note 2. Summary of Significant Accounting Policies Use of Estimates in the Preparation of Financial Statements Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (6) 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. Cash and Cash Equivalents We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the Consolidated and Combined Statements of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable. Restricted Cash Restricted cash consists of certificates of deposit in place to collateralize letters of credit. The letters of credit are required as part of normal business operations. The certificates of deposit will be in place for a period greater than 12 months and are considered noncurrent. Oil and Gas Properties We use the successful efforts method of accounting for natural gas and crude oil producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Costs to drill and develop development wells and costs to drill and develop exploratory wells that find proved reserves are also capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed. The following table reflects the net changes in capitalized exploratory well costs for the periods indicated: For Year Ended December 31, 2016 2015 2014 Balance, beginning of period $ 15,198 $ 11,134 $ — Balance at inception of common control — 6,385 — Additions to capitalized exploratory well costs pending the determination of proved reserves 60,847 96,726 11,134 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (68,981 ) (93,052 ) — Capitalized exploratory well costs charged to expense — (5,995 ) — Balance, end of period $ 7,064 $ 15,198 $ 11,134 We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable. We recorded impairment of $3.0 million and $1.2 million as exploration expense for unproved oil and gas properties for the year ended December 31, 2016 and 2015, respectively. We had no leasehold impairment expense for the year ended December 31, 2014. Capitalized costs of producing natural gas and crude oil properties and support equipment, net of estimated salvage values, are depleted by field using the units-of-production Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. We recorded impairment expense of $9.3 million and $24.7 million to proved oil and gas properties for the year ended December 31, 2015 and 2014, respectively. The impairment resulted from lower projected oil and gas prices and a drop in projected remaining reserves in East Texas and our non-core Oil and Gas Reserves The estimates of proved natural gas, crude oil and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 19—“Supplemental Oil and Gas Information (Unaudited)” for further information. Gathering System In 2015, our Oakfield subsidiary constructed and began operating a 15.2 mile 16” natural gas gathering system in order to provide sufficient, cost effective access to major markets for our existing and expected future production from new horizontal wells in North Louisiana. The wells are charged a fee for gathering services based on their throughput volumes and gas quality. In 2016, only wells operated by us were connected to the system. We are depreciating the Oakfield gathering assets on a straight-line basis over the current expected reserve life of wells connected to the system. Other Property and Equipment Other property and equipment includes our natural gas gathering system, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized. Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2016, 2015 and 2014, we recorded $0.1 million, $0.8 million $0.2 million in capitalized interest, respectively. Properties Acquired in Business Combinations Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions and Divestitures.” Asset Retirement Obligations We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production The fair value of the estimated cost is based on historical experience, managements’ expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated Environmental Costs As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Revenue Recognition and Oil and Gas Imbalances Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. We receive payment approximately one month after delivery for operated wells and up to three months after delivery for non-operated Incentive Units For details regarding incentive units issued by our predecessor, please see “Note 13. Incentive Units.” Accounts Receivable We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of crude oil, natural gas and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties. Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes two months of accrued revenues for operated properties and three months of accrued revenues for non-operated Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.1 million at both December 31, 2016 and 2015. Derivative Instruments We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price swaps collars and puts. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales. All derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current Lease Expenses We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis. Debt Issuance Costs Debt issuance costs associated with line-of-credit Fair Value Measurements Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements of Financial Instruments.” Income Taxes We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carry forwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our Consolidated and Combined Statement of Operations. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. Commitments and Contingencies Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Supplemental Cash Flow Information Supplement cash flow for the periods presented: For Year Ended December 31, 2016 2015 2014 Supplemental cash flows: Cash paid for interest $ 7,152 $ 7,253 $ 2,515 Noncash investing activities: (Decrease) increase in capital expenditures in accounts payables and accrued liabilities (4,492 ) 349 5,530 New Accounting Standards Definition of a Business Statement of Cash Flows—Restricted Cash a consensus of the FASB Emerging Issues Task Force Statement of Cash Flows—Classification of Certain Cash Receipts and Cash Payments Improvements to Employee Share-Based Payment Accounting Leases right-of-use Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently evaluating the standard and the impact on our financial statements and related footnote disclosures. Balance Sheet Classification of Deferred Taxes tax-paying Simplifying the Accounting for Measurement-Period Adjustments Presentation of Debt Issuance Cost line-of-credit line-of-credit line-of-credit Revenue from Contracts with Customers Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on our consolidated financial statements and footnote disclosures.

Acquisitions and Divestitures

Acquisitions and Divestitures	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 For the Six Months Ended 2017 2016 2017 2016 $2,199 $ 72 $ 2,798 $ 72 2017 Acquisitions The Acquisition. On June 30, 2017, we completed the Acquisition. The aggregate purchase price for the Acquisition, which is subject to customary adjustments as provided in the Acquisition Agreements, consisted of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (collectively, the “Adjusted Purchase Price”). The common stock consideration price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017 (the “Stock Issuance Agreement”), by and among us and KKR. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing of the Acquisition (in thousands): Consideration: Cash $ 533,609 Common stock 60,754 Total consideration 594,363 Preliminary Purchase Price Allocation: Proved oil and gas properties $ 264,144 Unproved oil and gas properties 333,778 Accounts receivable 967 Asset retirement obligations (2,500 ) Accrued liabilities (2,026 ) Total identifiable net assets $ 594,363 Supplemental Pro forma Information For the Three Months Ended June 30, For the Six Months Ended June 30, 2017 2016 2017 2016 Revenues $ 93,471 $ 55,198 $ 172,674 $ 100,868 Net Income 38,747 (7,674 ) 69,777 (17,510 ) Earnings per share (basic and diluted) 0.41 n/a 0.74 n/a Burleson 2017 Acquisitions. non-producing 2016 Acquisitions Burleson North Acquisition 10-K, 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 For the Three For the Six Revenues $ 43,393 $ 78,727 Net income (loss) (13,822 ) (28,051 ) Basic and diluted earnings per share n/a n/a	Note 3. Acquisitions and Divestitures We account for third-party acquisitions under the acquisition method. The assets acquired and the liabilities assumed have been measured at fair value based on various estimates. These estimates are based on key assumptions related to the business combination, including reviews of publicly disclosed information for other acquisitions in the industry, historical experience of the companies, data that was available through the public domain and due diligence reviews of the acquiree businesses. Acquisition-related transaction costs and acquisition-related restructuring charges are not included as components of consideration transferred but are accounted for as expenses in the period in which the costs are incurred. Acquisition-related costs Acquisition-related costs 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 Year Ended December 31, 2016 2015 2014 $553 $593 $1,450 2016 Acquisitions Burleson North Acquisition The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Preliminary Oil and gas properties $ 396,481 Other property and equipment 478 Accounts receivable 3,160 Asset retirement obligations (3,101 ) Accrued liabilities (7,206 ) Total identifiable net assets $ 389,812 Rosewood Acquisition November Acquisition The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date for the November Acquisition and Rosewood Acquisition (in thousands): Rosewood November Oil and gas properties 19,626 29,973 The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 and 2015 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company, the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Year Ended December 31, 2016 2015 Revenues $ 176,082 $ 172,044 Net income (loss) (34,894 ) (83,894 ) Basic and diluted earnings per unit n/a n/a 2015 Acquisitions Comstock Acquisition The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Comstock Oil and gas properties $ 102,628 Other property and equipment 500 Asset retirement obligations (112 ) Total identifiable net assets $ 103,016 2014 Acquisitions On February 7, 2014, the predecessor acquired certain oil and gas properties in east Texas for cash consideration of $16.0 million, net of customary post-closing adjustments. The purchase price was primarily allocated to oil and gas properties. On June 3, 2014, the predecessor acquired oil and gas producing properties and leases in north Louisiana for cash consideration of $37.1 million, net of customary post-closing adjustments. Assumed liabilities included suspended amounts payable to royalty and other working interest owners. The purchase price was primarily allocated to oil and gas properties. On October 13, 2014, the predecessor acquired oil and gas producing properties and leases in north Louisiana for cash consideration of $12.8 million, net of customary post-closing adjustments. Assumed liabilities include suspended amounts payable to royalty and other working interest owners. The purchase price was primarily allocated to oil and gas properties.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. Assets and Liabilities Measured at Fair Value on a Recurring Basis The carrying values of cash and cash equivalents, restricted cash, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at June 30, 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 June 30, 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 June 30, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Fair Value Measurements at June 30, 2017 Using Quoted Prices in Significant Other Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 53,379 $ — $ 53,379 Liabilities: Commodity derivatives $ — $ 1,623 $ — $ 1,623 Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant 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. The fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See “Note 8—Asset Retirement Obligations” for a summary of changes in AROs. • If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach. • Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. We did not record impairments during the three and six months ended June 30, 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 and six months ended June 30, 2017, we recorded $10.0 million and $10.7 million of impairments of unproved properties. We recorded $0.1 million in impairments on unproved properties for both the three and six months ended June 30, 2016.	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: Level 1 Level 2 Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis The carrying values of cash and cash equivalents, restricted cash, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2016 and December 31, 2015. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2016 and December 31, 2015 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 7 $ — $ — Liabilities: Commodity derivatives $ — $ 22,185 $ — $ 22,185 Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 9,764 $ — $ 9,764 Liabilities: Commodity derivatives $ — $ 248 $ — $ 248 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: • The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 8 for a summary of changes in AROs. • If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach. • Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. • During the years ended December 31, 2015 and 2014, we recognized $9.3 million and $24.7 million, respectively, of impairments. The impairments primarily related to certain properties located in East Texas and our non-core

Risk Management and Derivative

Risk Management and Derivative Instruments	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 establish a ceiling and floor price for expected future oil and natural gas sales. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and where the Company agrees to defer the premium paid or received until the time of settlement. Cash received on settled derivative positions during the three and six months ended June 30, 2017 is net of deferred premiums of $0.5 million and $0.6 million, respectively. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current set-off set-off See “Note 4—Fair Value Measurements of Financial Instruments” for further information. The following derivative contracts were in place at June 30, 2017: Remainder 2017 2018 2019 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 1,185,971 5,023,163 3,284,623 Weighted-average fixed price $ 52.57 $ 53.29 $ 53.80 Collar contracts: Volume (Bbls) 28,240 25,096 — Weighted-average floor price $ 50.00 $ 50.00 $ — Weighted-average ceiling price $ 62.10 $ 62.10 $ — Put options: Volume (Bbls) 1,215,036 597,850 410,525 Weighted-average floor price $ 55.00 $ 50.00 $ 50.00 Weighted-average put premium $ (4.77 ) $ (5.95 ) $ (5.95 ) Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 4,000,500 11,565,800 9,877,900 Weighted-average fixed price $ 3.12 $ 3.03 $ 2.81 Collar contracts: Volume (MMBtu) 2,760,000 — — Weighted-average floor price $ 3.00 $ — $ — Weighted-average ceiling price $ 3.36 $ — $ — Put options: Volume (MMBtu) 2,971,208 — — Weighted-average floor price $ 3.40 $ — $ — Weighted-average put premium $ (0.37 ) $ — $ — Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2017 and December 31, 2016 (in thousands). There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives Type Balance Sheet Location June 30, December 31, June 30, December 31, Commodity contracts Short-term derivative instruments $ 28,543 $ 4 $ 1,173 $ 14,091 Netting arrangements Short-term derivative instruments (351 ) (4 ) (351 ) (4 ) Net recorded fair value $ 28,192 $ — $ 822 $ 14,087 Commodity contacts Long-term derivative instruments $ 24,836 $ 3 $ 450 $ 8,094 Netting arrangements Long-term derivative instruments (401 ) (3 ) (401 ) (3 ) Net recorded fair value $ 24,435 $ — $ 49 $ 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 Unaudited Statements of Condensed Consolidated and Combined Operations. The following table details the gains and losses related to derivative instruments for the three and six months ending June 30, 2017 and 2016 (in thousands): Statements of Operations Location For the Three Months For the Six Months 2017 2016 2017 2016 Commodity derivative contracts (Gain) loss on derivative instruments $ (46,116 ) $ 15,610 $ (77,407 ) $ 12,364	Note 5. Risk Management and Derivative and Other Financial Instruments We have entered into certain derivative arrangements with respect to portions of our oil and natural gas production to reduce our sensitivity to volatile commodity prices. None of our derivative instruments are designated as cash flow hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve more predictable cash flows and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil and natural gas sales. Moreover, our derivative arrangements apply only to a portion of our production and provide only partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our risk management program in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements. Commodity Derivatives We have 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. 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 The following derivative contracts were in place at December 31, 2016: 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 9,029,600 11,565,800 9,877,900 Weighted-average fixed price $ 3.15 $ 3.03 $ 2.81 Collar contracts: Volume (MMBtu) 5,520,000 — — Weighted-average floor price $ 3.00 $ — $ — Weighted-average ceiling price $ 3.36 $ — $ — Put options: Volume (MMBtu) 1,068,350 — — Weighted-average floor price $ 3.40 $ — $ — Weighted-average put premium $ (0.35 ) $ — $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 2,146,300 1,638,500 1,381,300 Weighted-average fixed price $ 52.90 $ 53.68 $ 54.92 Collar contracts: Volume (Bbls) 60,784 25,096 — Weighted-average floor price $ 50.00 $ 50.00 $ — Weighted-average ceiling price $ 62.10 $ 62.10 $ — Put options: Volume (Bbls) 636,400 — — Weighted-average floor price $ 55.00 $ — $ — Weighted-average put premium $ (4.76 ) $ — $ — Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2016 and 2015. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2016 2015 2016 2015 Commodity contracts Short-term derivative instruments $ 4 $ 7,108 $ 14,091 $ 32 Netting arrangements Short-term derivative instruments (4 ) (32 ) (4 ) (32 ) Net recorded fair value $ — $ 7,076 $ 14,087 $ — Commodity contacts Long-term derivative instruments $ 3 $ 2,656 $ 8,094 $ 216 Netting arrangements Long-term derivative instruments (3 ) (216 ) (3 ) (216 ) Net recorded fair value $ — $ 2,440 $ 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 Combined and Consolidated Financial Statements. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2016, 2015 and 2014: Statements of Operations Location For the Year Ended December 31, 2016 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ 26,771 $ (13,854 ) $ (6,514 )

Accounts Receivable

Accounts Receivable	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Receivables [Abstract]
Accounts Receivable	Note 6. Accounts Receivable Accounts receivable consist of the following (in thousands): June 30, 2017 December 31, Oil, natural gas and NGL sales $ 25,437 $ 13,390 Joint interest billings 13,710 7,898 Derivative receivable 1,948 — Severance tax 33 392 Other current receivables 969 4,848 Allowance for doubtful accounts (100 ) (100 ) Total $ 41,997 $ 26,428	Note 6. Accounts Receivable Accounts receivable consist of the following: At December 31, 2016 2015 Oil, gas and NGL sales $ 13,390 $ 9,412 Joint interest billings 7,898 3,455 Severance tax 392 531 Other current receivables(1) 4,848 389 Allowance for doubtful accounts (100 ) (50 ) Total $ 26,428 $ 13,737 (1) Primarily relates to a receivable related to our North Burleson Acquisition. The following table presents our allowance for doubtful accounts activity for the periods indicated: For the Year Ended December 31, 2016 2015 2014 Balance at beginning of period $ 50 $ — $ — Charged to costs and expenses 50 50 — Balance at end of period $ 100 $ 50 $ —

Accrued Liabilities

Accrued Liabilities	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Accrued Liabilities	Note 7. Accrued Liabilities Accrued liabilities consist of the following (in thousands): June 30, 2017 December 31, Capital expenditures $ 100,491 $ 17,934 Deferred rent 398 386 Lease operating expense 3,070 2,608 General and administrative 4,377 1,471 Severance and ad valorem taxes 4,678 194 Interest expense 10,043 346 Derivative payable — 428 Other accrued liabilities(1) 2,689 4 Total $ 125,746 $ 23,371 (1) Other accrued liabilities include $1.5 million for seismic acquisition.	Note 7. Accrued Liabilities Accrued liabilities consist of the following: At December 31, 2016 2015 Capital expenditures $ 17,934 $ 26,105 Deferred rent 386 363 Lease operating expense 2,608 1,459 General and administrative 1,471 242 Severance and ad valorem taxes 194 415 Interest expense 346 192 Other accrued liabilities 432 6 Total $ 23,371 $ 28,782

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 8. Asset Retirement Obligations The Company’s AROs primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2017 (in thousands): Asset retirement obligations at beginning of period $ 11,033 Accretion expense 305 Liabilities incurred 2,698 Revisions (286 ) Asset retirement obligations at end of period 13,751 Less: current portion (90 ) Asset retirement obligations—long-term $ 13,661	Note 8. Asset Retirement Obligations The following table presents the changes in the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014: For the Year Ended December 31, 2016 2015 2014 Asset retirement obligations at beginning of period $ 7,020 $ 5,935 $ 4,991 Balance at inception of common control (February 17, 2015) — 37 — Accretion expense 407 354 309 Liabilities incurred 3,723 686 676 Liabilities settled (5 ) (8 ) — Revisions (112 ) 16 (41 ) Asset retirement obligations at end of period 11,033 7,020 5,935 Less: current portion 90 90 90 Asset retirement obligations—long-term $ 10,943 $ 6,930 $ 5,845

Long Term Debt

Long Term Debt	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Long Term Debt	Note 9. Long Term Debt Our debt obligations consisted of the following at the dates indicated (in thousands): Credit Facility June 30, 2017 December 31, WRD revolving credit facility $ 146,000 $ 242,750 2025 Senior Notes (as defined below)(1) 350,000 — Unamortized discounts (2,541 ) — Unamortized debt issuance costs—2025 Senior Notes (8,426 ) — Total long-term debt $ 485,033 $ 242,750 (1) The estimated fair value of this fixed-rate debt was $328.1 million at June 30, 2017. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. 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. Borrowing Base Credit facilities tied to borrowing base are common throughout the oil and natural gas industry. Our borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for our revolving credit facility was the following at the date indicated (in thousands): June 30, 2017 Credit Facility WRD revolving credit facility $ 650,000 Amendment to Credit Agreement On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a Second Amendment (the “Amendment”) to the Credit Agreement dated as of December 19, 2016, among the Company, the Administrative Agent and the other agents and lenders party thereto (as amended, the “Credit Agreement”). The Amendment, among other things, modified the Credit Agreement to (i) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock (see Note 10), (ii) increase the Company’s borrowing base and elected commitment amount from $450 million to $650 million, (iii) increase the annual cap on certain restricted payments from $50 million to $75 million, and (iv) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified capital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company’s leverage covenant. 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 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 June 30, For the Six Months Ended June 30, Credit Facility 2017 2016 2017 2016 WRD revolving credit facility 3.40 % n/a 3.48 % n/a WHR II revolving credit facility terminated December 2016 n/a 3.00 % n/a 3.00 % Esquisto—revolving credit facility terminated December 2016 n/a 2.80 % n/a 2.81 % Esquisto—revolving credit facility terminated January 2016 n/a n/a n/a 2.97 % Esquisto—Second lien terminated in January 2016 n/a n/a n/a 9.50 % Unamortized Debt Issuance Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands): June 30, 2017 December 31, WRD revolving credit facility(1) $ 3,966 $ 2,904 6.875% senior unsecured notes, due February 2025 8,426 n/a Total $ 12,392 $ 2,904 (1) We classified $0.9 million and $0.6 million of unamortized deferred financing costs at June 30, 2017 and December 31, 2016, respectively, under current assets as a component of “prepaid expenses and other current assets.”	Note 9. Long Term Debt Our debt obligations consisted of the following at the dates indicated: For the Year Ended December 31, Credit Facility 2016 2015 WRD revolving credit facility $ 242,750 $ — WHR II revolving credit facility terminated December 2016 — 118,000 Esquisto—revolving credit facility terminated December 2016 — 50,000 Esquisto—revolving credit facility terminated January 2016 — 40,000 Esquisto—second lien terminated in January 2016 — 30,000 Unamortized debt issuance costs—second lien — (143 ) Total long-term debt $ 242,750 $ 237,857 Revolving Credit Facility On December 19, 2016 after the closing of our initial public offering, we, as borrower, and certain of our current and future subsidiaries, as guarantors, entered into a five-year, $1.0 billion senior secured revolving credit facility, which had an initial borrowing base of $450.0 million but was automatically reduced to $362.5 million in connection with the consummation of our 2025 Senior Notes (defined below) offering on February 1, 2017. Our revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion consistent with their normal and customary oil and gas lending practices semi-annually (in the case of scheduled redeterminations), from time to time at our election in connection with material acquisitions, or no more frequently than twice in any fiscal year at the request of the required lenders or us (in the case of interim redeterminations), in each case based on engineering reports with respect to our estimated oil, NGL and natural gas reserves, and our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base pursuant to a redetermination, while only required lender approval is required to maintain or decrease the borrowing base pursuant to a redetermination. The borrowing base will also automatically decrease upon the issuance of certain debt, including notes, the sale or other disposition of certain assets and the early termination of certain swap agreements. In the future, we may be unable to access sufficient capital under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations. A decline in commodity prices could result in a redetermination that lowers our borrowing base and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility. Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 85% (or 75% with respect to certain properties prior to February 2, 2017) of the total value, as determined by the administrative agent, of the proved reserves attributable to our oil and natural gas properties using a discount rate of 9%, all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property but excluding equity interests in and assets of unrestricted subsidiaries. Additionally, borrowings under our revolving credit facility will bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies from 1.25% to 2.25% per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage. Our revolving credit facility requires us to maintain (x) a ratio of total debt to EBITDAX (as defined under our revolving credit facility) of not more than 4.00 to 1.00 and (y) a ratio of current assets (including availability under the facility) to current liabilities of not less than 1.00 to 1.00. Additionally, our revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness. Events of default under our revolving credit facility will include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond any applicable cure period, default under any other material debt, change of control, bankruptcy or other insolvency event and certain material adverse effects on our business. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under our revolving credit facility, together with accrued interest, fees and other obligations under the credit agreement, could be declared immediately due and payable. WHR II Revolving Credit Facility We repaid and terminated WHR II’s prior revolving credit facility in connection with the completion of our initial public offering. Esquisto Revolving Credit Facility We repaid and terminated Esquisto’s prior revolving credit facility in connection with the completion of our initial public offering. Esquisto Terminated Revolving Credit Facility and Second Lien Loan. Esquisto retired and terminated one of their revolving credit facilities and second lien loan in January 2016 in connection with the merger of Esquisto I and Esquisto II. 2025 Senior Notes Subsequent Event. 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 are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries. The consummation of our 2025 Senior Notes offering automatically reduced the borrowing base of our revolving credit facility by $87.5 million. See Note 20 for additional information regarding the 2025 Senior Notes. 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 Year Ended December 31, Credit Facility 2016 2015 2014 WRD revolving credit facility 3.52 % n/a n/a WHR II revolving credit facility terminated December 2016 n/a 2.60 % 2.40 % Esquisto—revolving credit facility terminated December 2016 n/a 3.13 % n/a Esquisto—revolving credit facility terminated January 2016 n/a 2.97 % n/a Esquisto—Second lien terminated in January 2016 n/a 9.25 % n/a Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated (dollars in thousands): At December 31, 2016 2015 WRD revolving credit facility $ 2,904 n/a WHR II revolving credit facility terminated December 2016 n/a 581 Esquisto—revolving credit facility terminated December 2016 n/a 494 Esquisto—second lien terminated in January 2016 n/a 143 $ 2,904 $ 1,218

Equity

Equity	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Equity [Abstract]
Equity	Note 11. Equity Common Stock The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common stock issued for the six months ended June 30, 2017: Balance, December 31, 2016 91,680,441 Common stock issued 7,815,225 Restricted common stock issued 1,640,351 Balance, June 30, 2017 101,136,017 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. On June 30, 2017, pursuant to the Acquisition Agreements, we issued 5,518,125 shares of our common stock valued at approximately $60.8 million as partial consideration to KKR. See Note 3 for additional information regarding the Acquisition. See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted 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. Previous Owner Equity Our previous owner received capital contributions of $25.0 million from its members during the six months ended June 30, 2016. Predecessor Equity The predecessor received capital contributions of $13.3 million from its members during the six months ended June 30, 2016.	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 year ended December 31, 2016: Balance, January 1, 2016 — Shares of common stock issued in connection with Corporate Reorganization 62,518,680 Shares of common stock issued in initial public offering 27,500,000 Shares of common stock issued in connection with Rosewood Acquisition 1,308,427 Restricted common shares issued 353,334 Balance, December 31, 2016 91,680,441 See Note 12 for additional information regarding restricted common shares 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 restricted stock award. Preferred Stock Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. Each class or series of preferred stock will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders. There are no shares issued and outstanding as of December 31, 2016. Dividend Policy We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our revolving credit facility places restrictions on our ability to pay cash dividends. Predecessor Equity The predecessor received capital contributions of $10.8 million, $125.9 million and $89.4 million from its members during the year ended December 31, 2016, 2015 and 2014, respectively. Promissory note advances were available to management to fund future capital commitments and carried an interest rate of 2.5%. The table below summarizes advances and payments of the promissory note advances for the years ended December 31, 2016, 2015 and 2014: Principal Interest Total Balance, December 31, 2013 $ 9,702 $ 97 $ 9,799 Advances 9,403 — 9,403 Payments (17,454 ) (303 ) (17,757 ) Accrued Interest — 245 245 Balance, December 31, 2014 1,651 39 1,690 Advances 1,096 — 1,096 Payments (380 ) (13 ) (393 ) Accrued Interest — 50 50 Balance, December 31, 2015 2,367 76 2,443 Advances 101 — 101 Payments (20 ) — (20 ) Accrued Interest — 51 51 Dissolution (2,448 ) (127 ) (2,575 ) Balance, December 31, 2016 $ — $ — $ — On November, 9, 2016, the management members conveyed to the predecessor certain ownership interests in the predecessor in exchange for the discharge in full and the termination of all the promissory note advances then outstanding. The promissory note advances and the related accrued interest receivable are presented in the balance sheet as a deduction from predecessor equity. Previous Owner Equity The previous owner’s received capital contributions of $97.0 million and $208.4 million from its members during the year ended December 31, 2016 and for the period of February 17, 2015 to December 31, 2015, respectively. During the period from February 17, 2015 to December 31, 2015, Esquisto received property contributions of $40.1 million from its members that primarily consisted of developed and undeveloped properties in the East Texas Eagle Ford, Austin Chalk and Pecan Gap formations in Lee County, Washington County and Brazos County, Texas. On February 17, 2015, NGP acquired a controlling interest in Esquisto from an Esquisto member not affiliated with NGP. NGP’s basis exceeded the net book value by $16.1 million associated with this transaction. In May 2015, NGP acquired additional interests in Esquisto from another Esquisto member not affiliated with NGP. NGP’s basis exceeded the net book value by $26.6 million associated with this transaction. As a result of the Corporate Reorganization (as discussed in Note 1) and common control accounting, Esquisto’s net assets were recorded at NGP’s historical cost basis.

Earnings Per Share

Earnings Per Share	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Share	Note 12. Earnings Per Share The following sets forth the calculation of earnings (loss) per share, or EPS, for the three and six months ending June 30, 2017 (in thousands, except per share amounts). In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. For the Three For the Six Numerator: Net income (loss) available to WildHorse Development $ 26,366 $ 46,618 Less: Preferred stock dividends 73 73 Less: Undistributed earnings allocated to participating securities 387 434 Net income (loss) available to common stockholders $ 25,906 $ 46,111 Denominator: Weighted-average common shares outstanding (in thousands)(1) 93,685 93,452 Basic EPS $ 0.28 $ 0.49 Diluted EPS(1) $ 0.28 $ 0.49 (1) The Company used the two-class if-converted	Note 11. Earnings per share The following sets forth the calculation of earnings (loss) per share, or EPS, for the year ending December 31, 2016 (in thousands, except per share amounts): Numerator: Net income (loss) available to WildHorse Resources $ (10,397 ) Denominator: Weighted-average common shares outstanding (in thousands)(1) 91,327 Basic EPS $ (0.11 ) Diluted EPS(1) $ (0.11 ) (1) The Company determines the more dilutive of either the two-class two-class

Long Term Incentive Plans

Long Term Incentive Plans	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Long Term Incentive Plans
Long Term Incentive Plans	Note 13. Long Term Incentive Plans In connection with our initial public offering, our board of directors adopted the 2016 Long-Term Incentive Plan (or “2016 LTIP”). The 2016 LTIP, authorizes the issuance of 9,512,500 shares of our common stock. The following table summarizes information regarding restricted common stock awards granted under the 2016 LTIP for the periods presented: Number of Weighted- Average Grant Restricted common stock outstanding at December 31, 2016 353,334 $ 14.50 Granted(2) 1,640,351 $ 13.94 Restricted common stock outstanding at June 30, 2017 1,993,685 $ 14.04 (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 $22.9 million based on grant date market prices ranging from $13.94 per share to $14.22 per share. For the three and six months ended June 30, 2017, we recorded $1.3 million and $1.8 million of recognized compensation expense, respectively, associated with these awards. Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $26.1 million at June 30, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.82 years.	Note 12. Long Term Incentive Plans In connection with the initial public offering, our Board adopted the 2016 Long-Term Incentive Plan (or “2016 LTIP”). The 2016 LTIP, authorizes the issuance of 9,512,500 shares of our common stock. As of December 31, 2016, we had granted 353,334 restricted shares to certain officers and directors. The following table summarizes information regarding restricted common share awards granted under the 2016 LTIP for the periods presented: Number of Weighted- Restricted common shares outstanding at January 1, 2016 $ — $ — Granted(2) 353,334 $ 14.50 Restricted common shares outstanding at December 31, 2016 $ 353,334 $ 14.50 (1) Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common share awards granted in 2016 was $5.1 million based on grant date market price of $14.50 per share. For the year ended December 31, 2016, we recorded $0.1 million of recognized compensation expense associated with these awards. Unrecognized compensation cost associated with the restricted common share awards was an aggregate of $5.0 million at December 31, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.86 years.

Incentive Units

Incentive Units	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Compensation Related Costs [Abstract]
Incentive Units	Note 14. 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 at June 30, 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 non-cash The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following key assumptions: Incentive Unit Expected life (years) 1.04 - Expected volatility (range) 54.0% - 62.0% Dividend yield 0.0% Risk-free rate (range) 1.24% - 1.91%	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. Holders of incentive units would have been entitled to distributions ranging from 20% to 40% when declared, but only after cumulative distribution thresholds (payouts) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. The incentive units were being accounted for as 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 year ended December 31, 2016, 2015 and 2014, respectively. 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, who became responsible for making all payments, distributions and settlements relating to the exchanged incentive units. While any such payments, distributions and settlements will not involve any cash payments by us, we will recognize non-cash In connection with the Corporate Reorganization, 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 WildHorse Holdings incentive units, Esquisto Holdings incentive units and Acquisition Co. Holdings incentive units will each vest in three equal annual installments beginning on the first anniversary of the applicable date of grant. The incentive units are entitled to a portion of future distributions by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings in excess of the value of our common stock held by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings based upon the initial public offering price of such common stock plus a 5% internal rate of return. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will be responsible for making all payments, distributions and settlements to all award recipients relating to the WildHorse Holdings incentive units, Esquisto Holdings incentive units and Acquisition Co. Holdings incentive units, respectively. While any such payments, distributions and settlements are not expected to involve any cash payment by us, we expect to recognize non-cash Vesting of all incentive units is generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested are forfeited if an employee is no longer employed. All incentive units will be forfeited if a holder resigns whether the incentive units are vested or not. If the payouts have not yet occurred, then all incentive units, whether or not vested, will be forfeited automatically (unless extended).

Related Party Transactions

Related Party Transactions	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Note 15. Related Party Transactions Board of Directors Relationships Mr. Grant E. Sims has served as a member of our board of directors since February 2017. Mr. Sims has served as a director and Chief Executive Officer of the general partner of Genesis Energy Partners, L.P. (“Genesis”) since August 2006 and Chairman of the board of directors of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the three and six months ended June 30, 2017, we received $0.6 million and $1.5 million, respectively, from Genesis. NGP Affiliated Companies Carlyle Group, L.P. NGP ECM. Highmark Energy Operating, LLC. non-operated Cretic Energy Services, LLC. PennTex Midstream Partners, LP. WildHorse Resources, LLC non-operated CH4 Energy. non-operated Garland Exploration LLC. non-operated Promissory Notes. Previous Owner Related Party Transactions Notes payable to members. Services provided by member. Operator. Related Party Agreements Stockholders’ Agreement A discussion of this agreement is included in our 2016 Form 10-K. Registration Rights Agreement On June 30, 2017, in connection with the Acquisition, our registration rights agreement was amended and restated in order to grant certain registration rights to KKR and the Carlyle Investor. Pursuant to the amended and restated registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. Transition Services Agreement Upon the closing of our initial public offering, we entered into a transition services agreement with CH4 Energy IV, LLC, PetroMax and Crossing Rocks Energy, LLC (collectively, the “Service Providers”), pursuant to which the Service Providers agreed to provide certain engineering, land, operating and financial services to us for six months relating to our Eagle Ford Acreage. In exchange for such services, we agreed to pay a monthly management fee to the Service Providers. NGP and certain former management members of Esquisto own the Service Providers. During the three and six months ended June 30, 2017, we paid the Service Providers less than $0.1 million and $0.1 million, respectively.	Note 14. Related Party Transactions Corporate Reorganization As described in Note 1, in connection with our initial public offering, we completed certain reorganization transactions pursuant to which we acquired all of the interests in WHR II, Esquisto and Acquisition Co. owned by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively, in exchange for 21,200,084 shares, 38,755,330 shares and 2,563,266 shares, respectively, of our common stock. Board of Directors and Executive Officer 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 the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the fiscal year ended December 31, 2016, we received $2.8 million from Genesis. In addition, Mr. Richard D. Brannon’s son who had been an employee of a CH4 Energy entity (an NGP affiliated company), joined the Company as a non-officer Our chief executive officer’s sister-in-law non-officer NGP Affiliated Companies Highmark Energy Operating, LLC non-operated Cretic Energy Services, LLC Multi-Shot, LLC PennTex Midstream Partners, LP Promissory Notes WildHorse Resources, LLC non-operated A management services agreement was executed on August 8, 2013, where WHRM began providing general, administrative and employee services to WHR II as well as WHR. WHRM shared costs were also subject to the same sharing ratio as the asset and cost sharing agreement between WHR and WHR II. As a result of this agreement, we made net payments of $6.0 million to WHRM in 2014. On June 18, 2014, (i) the management agreement and the asset cost sharing agreement were terminated, (ii) WHR II purchased WHRM from WHR for $0.2 million and (iii) WHR II, through WHRM, began providing accounting and operating transition services to WHR, including administrative and land services, pursuant to the management services agreement. As a result of the management services agreement, WHR II made $57.6 million in net payments to WHR in 2015 but received net payments of $53.0 million from WHR and its affiliates in 2014. WHR II was owed $1.6 million, net, as of December 31, 2015. On February 25, 2015, the management services agreement was terminated effective March 1, 2015. During the year ended December 31, 2016, we paid net payments of $0.1 million to WHR’s parent company for non-operated NGP X US Holdings LP Previous Owner Related Party Transactions Notes payable to members These notes were payable to members by December 31, 2022 and bore interest after a year at the Applicable Federal Rate compounded annually paid at maturity. In connection with our initial public offering, the Esquisto notes payable to its members were paid off. Certain CH4 Energy entities received $3.6 million. These CH4 Energy entities are NGP affiliated companies and Mr. Brannon is President of these entities. Garland Exploration, LLC and Crossing Rocks Energy, LLC (“Crossing Rocks”) received $5.5 million and $1.3 million, respectively. These entities are also NGP affiliated companies. Services provided by member Operator Related Party Agreements Registration Rights Agreement Demand Rights lock-up We are also not obligated to effect any demand registration in which the anticipated aggregate offering price for our common stock included in such offering is less than $30 million. Once we are eligible to effect a registration on Form S-3, In addition, each of the holders (or its permitted transferees) have the right to require us, subject to certain limitations, to effect a distribution of any or all of its shares of our common stock by means of an underwritten offering. In general, any demand for an underwritten offering (other than the first requested underwritten offering made in respect of a prior demand registration and other than a requested underwritten offering made concurrently with a demand registration) shall constitute a demand request subject to the limitations set forth above. Piggyback Rights Stockholders’ Agreement • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own greater than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate up to three nominees to our board of directors; • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 35% of our common stock but less than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate two nominees to our board of directors; • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 15% of our common stock but less than 35% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors and can nominate a third nominee by agreement between them; • so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 5% of our common stock but less than 15% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors; and • once WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own less 5% of our common stock, WildHorse Holdings and Esquisto Holdings will not have any board designation rights. Pursuant to the stockholders’ agreement we are required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by WildHorse Holdings and Esquisto Holdings. In addition, the stockholders’ agreement provides that for so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, own at least 15% of the outstanding shares of our common stock, WildHorse Holdings and Esquisto Holdings will have the right to cause any committee of our board of directors to include in its membership at least one director designated by WildHorse Holdings or Esquisto Holdings, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to WildHorse Holdings and Esquisto Holdings to designate directors are additive to and not intended to limit in any way the rights that WildHorse Holdings, Esquisto Holdings, Acquisition Co. or any of their affiliates, including NGP XI, may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the Delaware General Corporation Law. Transaction Services Agreement

Segment Disclosures

Segment Disclosures	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Disclosures	Note 16. 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 For the Six Months Ended June 30, 2017 2016 2017 2016 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 26,366 $ (18,281 ) $ 46,618 $ (32,497 ) Interest expense, net 6,633 1,781 12,204 3,753 Income tax (benefit) expense 15,193 111 26,893 250 Depreciation, depletion and amortization 33,229 19,923 59,672 41,986 Exploration expense 11,504 80 13,119 7,523 (Gain) loss on derivative instruments (46,116 ) 15,610 (77,407 ) 12,364 Cash settlements received (paid) on derivative instruments 2,076 2,525 1,093 5,898 Stock-based compensation 1,308 — 1,803 — Acquisition related costs 2,199 72 2,798 72 Debt extinguishment costs — — (11 ) 358 Public offering costs — — 182 — Non-cash — (103 ) — (286 ) Total Adjusted EBITDAX $ 52,392 $ 21,718 $ 86,964 $ 39,421	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 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: For the Year Ended December 31, 2016 2015 2014 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ (47,076 ) $ (33,040 ) $ (14,437 ) Interest expense, net 7,834 6,943 2,680 Income tax (benefit) expense (5,575 ) 604 (158 ) Depreciation, depletion and amortization 81,757 56,244 15,297 Exploration expense 12,026 18,299 1,597 Impairment of proved oil and gas properties — 9,312 24,721 (Gain) loss on derivative instruments 26,771 (13,854 ) (6,514 ) Cash settlements received (paid) on derivative instruments 4,975 11,517 (2,712 ) Stock-based compensation 68 — — Acquisition related costs 553 593 1,450 (Gain) loss on sale of properties 43 — — Debt extinguishment costs 1,667 — — Initial public offering costs 1,560 — — Non-cash (286 ) (760 ) (647 ) Total Adjusted EBITDAX $ 84,317 $ 55,858 $ 21,277 Major Customers Major Customers For the Year Ended December 31, 2016 2015 2014 Energy Transfer Equity, L.P. and subsidiaries 63 % 36 % 10 % Royal Dutch Shell plc and subsidiaries 12 % 20 % 41 % Cima Energy LTD 15 % 16 % n/a BP Corporation North America n/a n/a 31 %

Income Taxes

Income Taxes	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 17. 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 tax; 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 and six months ended June 30, 2017 was $15.2 million and $26.9 million, respectively, compared to income tax expense of $0.1 million and $0.3 million for the three and six months ended June 30, 2016, respectively. The period-to-period The Company reported no liability for unrecognized tax benefits as of June 30, 2017 and expects no significant change to the unrecognized tax benefits in the next twelve months.	Note 16. Income Taxes The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2016 2015 2014 Current income taxes: Federal $ — $ — $ (31 ) State — — — Total income tax benefit (expense) — — (31 ) Deferred income taxes: Federal 5,737 77 156 State (162 ) (681 ) 33 Total deferred income tax benefit (expense) 5,575 (604 ) 189 Total income tax benefit (expense) $ 5,575 $ (604 ) $ 158 The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2016 2015 2014 Expected tax benefit (expense) ad federal statutory rate $ 18,428 $ 11,353 $ 5,108 State income tax benefit (expense), net of federal benefit (105 ) (680 ) 32 Pass-through entities(1) (12,499 ) (11,315 ) (5,010 ) Valuation allowance (234 ) — — Other (15 ) 38 28 Total income tax benefit (expense) $ 5,575 $ (604 ) $ 158 (1) Our predecessor was a pass-through entity for federal income tax purposes. The components of net deferred income tax liabilities are as follows: For the Year Ended December 31, 2016 2015 Deferred income tax assets: Tax carryovers $ 2,597 $ 60 Asset retirement obligation 4,083 8 Derivatives 8,184 — Other 870 — Total deferred income tax assets 15,734 68 Valuation allowance 232 — Net deferred income tax assets 15,502 68 Deferred income tax liabilities: Property, plant and equipment 127,835 882 Derivatives — 25 Other 219 13 Total deferred income tax liabilities 128,054 920 Net deferred income tax liabilities 112,552 852 The Company recorded a deferred tax liability of approximately $117.3 million through stockholders’ equity in connection with its initial public offering and the related restructuring transactions. The tax basis of its assets and liabilities was unchanged as a result of its initial public offering and the related restructuring transactions, which is reported as a transaction among stockholders for financial reporting purposes. Uncertain Income Tax Position more-likely-than-not Tax Audits and Settlements Tax Attribute Carryforwards and Valuation Allowance pre-contribution

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 18. Commitments and Contingencies Litigation & Environmental We are party to various ongoing and potential legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of June 30, 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 June 30, 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 June 30, 2017 and December 31, 2016, respectively, and were recorded on our balance sheet as restricted cash. Dedicated Fracturing Fleet Services Agreements During the six months ended June 30, 2017, the Company entered into two dedicated fracturing fleet services agreements to complete wells in a timely manner following conclusion of drilling operations. On March 15, 2017, we entered into 20-month On June 1, 2017, we entered into a 23-month 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 six months ended June 30, 2017.	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 December 31, 2016 and 2015. 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. At December 31, 2016 and 2015, no environmental obligations were recognized. Transportation WHR II was assigned a firm gas transportation service agreement with Regency Intrastate Gas LLC (the “Transporter”) as a result of our property acquisition on August 8, 2013. Under the terms of the agreement, we are obligated to pay total daily transportation fees not to exceed $0.30 per MMBtu per day for quantities of 40,000 MMBtu per day to the Transporter until March 5, 2019. Our minimum commitments to the Transporter as of December 31, 2016 is as follows (in thousands): 2017 2018 2019 $4,380 $4,380 $768 Lease Obligations We currently lease corporate office space through May 31, 2021. Total general and administrative rent expense for the year ended December 31, 2016, 2015 and 2014 was $0.9 million, $0.8 million and $0.4 million, respectively. WHRM entered into the office lease agreement in 2013 that has escalating payments between July 2014 and May 2021. The average annual lease payment is $1.2 million over the life of the lease. We have entered into drilling services agreements with varying terms. We have entered into compressor and equipment rental agreements with various terms. The compressor and equipment rental agreements expire at various times with the latest expiring in March 2017. Most of these agreements contain 30 day termination clauses. Total compressor and equipment rental expense incurred in 2016, 2015 and 2014 was $0.6 million, $1.0 million and $0.7 million, respectively. The table below reflects our minimum commitments as of December 31, 2016: 2017 2018 2019 2020 Thereafter Office Lease $ 1,235 $ 1,259 $ 1,282 $ 1,306 $ 548 Compressor and Equipment 1,599 — — — — Total $ 2,834 $ 1,259 $ 1,282 $ 1,306 $ 548

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 18. Quarterly Financial Information (Unaudited) The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2016 Revenues $ 25,127 $ 29,715 $ 33,239 $ 39,261 Operating income (loss) (15,005 ) (704 ) 1,457 (1,976 ) Net income (loss) (14,216 ) (18,281 ) 3,057 (17,636 ) Net income (loss) allocated to predecessor (11,699 ) (13,016 ) (2,104 ) (7,179 ) Net income (loss) allocated to previous owner (2,517 ) (5,265 ) 5,161 (60 ) Net income (loss) available to common stockholders n/a n/a n/a (10,397 ) Basic earnings per share n/a n/a n/a $ (0.11 ) Diluted earnings per share n/a n/a n/a $ (0.11 ) For the Year Ended December 31, 2015 Revenues $ 11,472 $ 21,238 $ 25,416 $ 28,209 Operating income (loss) (5,334 ) (16,502 ) (7,501 ) (9,863 ) Net income (loss) (4,217 ) (18,649 ) (4,712 ) (5,462 ) Net income (loss) allocated to predecessor (2,653 ) (18,396 ) (4,041 ) (4,865 ) Net income (loss) allocated to previous owner (1,564 ) (253 ) (671 ) (597 )

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	Note 19. Supplemental Oil and Gas Information (Unaudited) Oil and Natural Gas Reserves Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves are, with respect to WHR II, prepared by WHR II and audited by Cawley, its independent reserve engineer. With respect to Esquisto, the proved reserves were prepared by Cawley, its independent reserve engineer, for 2015. Esquisto’s proved reserves for 2016 were internally prepared and audited by Cawley. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. For the Year Ended December 31, 2016 2015 2014 Oil ($/Bbl) West Texas Intermediate(1) $ 42.75 $ 46.79 $ 91.48 NGL ($/Bbl) West Texas Intermediate(1) $ 42.75 $ 46.79 $ 91.48 Natural Gas ($/Mmbtu) Henry Hub(2) $ 2.48 $ 2.59 $ 4.35 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. The following tables set forth estimates of the net reserves as of December 31, 2016, 2015 and 2014, respectively: For the Year Ended December 31, 2016 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 36,650 344,959 8,897 103,040 Extensions, discoveries and additions 18,870 32,782 2,606 26,940 Purchase of minerals in place 26,835 13,545 1,823 30,916 Production (1,848 ) (17,820 ) (471 ) (5,289 ) Revision of previous estimates 6,940 (48,364 ) (1,981 ) (3,102 ) End of year 87,447 325,102 10,874 152,505 Proved developed reserves: Beginning of year 7,503 142,990 2,235 33,570 End of year 19,192 145,880 3,765 47,270 Proved undeveloped reserves: Beginning of year 29,147 201,969 6,662 69,470 End of year 68,255 179,222 7,109 105,235 For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 222 249,787 324 42,177 Balance at inception of common control (February 17, 2015) 7,400 6,183 1,637 10,068 Extensions, discoveries and additions 27,598 143,338 5,976 57,464 Purchase of minerals in place 1,972 4,296 710 3,398 Production (968 ) (14,847 ) (351 ) (3,794 ) Revision of previous estimates 426 (43,798 ) 601 (6,273 ) End of year 36,650 344,959 8,897 103,040 Proved developed reserves: Beginning of year 222 122,780 324 21,009 End of year 7,503 142,990 2,235 33,570 Proved undeveloped reserves: Beginning of year — 127,007 — 21,168 End of year 29,147 201,969 6,662 69,470 For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 175 210,293 — 35,224 Extensions and discoveries 63 4,318 573 1,356 Purchase of minerals in place 17 13,684 — 2,298 Production (31 ) (9,388 ) (41 ) (1,637 ) Revision of previous estimates (2 ) 30,880 (208 ) 4,936 End of year 222 249,787 324 42,177 Proved developed reserves: Beginning of year 175 97,734 — 16,464 End of year 222 122,780 324 21,009 Proved undeveloped reserves: Beginning of year — 112,559 — 18,760 End of year — 127,007 — 21,168 Noteworthy amounts included in the categories of proved reserve changes in the above tables include: • During 2016, extensions, discoveries and additions increased proved reserves by 4,131 MBoe and 22,809 MBoe related to drilling in the RCT field in Louisiana and Eagle Ford, respectively. • During 2016, purchase of minerals in place of 30,916 MBoe was primarily attributable to the Burleson North Acquisition. • During 2016, we had downward revisions of proved reserves of 3,102 MBoe, of which 711 MBoe related to commodity price changes and 2,391 MBoe was performance related. • During 2015, extensions, discoveries and additions increased proved reserves by 20,881 MBoe related to drilling in the RCT field in Louisiana by our predecessor. For the period from February 17, 2015 to December 31, 2015, extensions and discoveries increased proved reserves by 36,583 MBoe related to drilling in the Eagle Ford horizons in Burleson County, Texas by the previous owner. • For the period from February 17, 2015 to December 31, 2015, purchase of minerals in place by the previous owner of 3,398 MBoe was primarily attributable to the producing wells acquired from a subsidiary of Comstock Resources, Inc. in July 2015. • During 2015, our predecessor had downward revisions of proved reserves of 7,450 MBoe, of which 3,410 MBoe related to commodity price changes and 4,040 MBoe related to downward revisions resulting from technical changes. For the period from February 17, 2015 to December 31, 2015, revisions of previous estimates attributable to the previous owner were primarily due to operational efficiencies gained through increased experience in the Eagle Ford area (increase of approximately 1,315 MBoe) partially offset by decreased commodity prices which decreased the useful lives of the wells, decreasing ultimate reserves recovered (decrease of approximately 139 MBoe). • During 2014, extensions, discoveries and additions increased proved reserves by 1,356 MBoe related to drilling two horizontal wells in East Texas by our predecessor. • During 2014, our predecessor acquired 2,298 MBoe of proved reserves, of which 1,888 MBoe was for non-core • During 2014, our predecessor had upward performance revisions to total proved reserves of 4,937 MBoe, of which 3,043 MBoe related to gas processing, 1,405 MBoe related to lease operating expense reductions and 517 MBoe related to changes in commodity prices, partially offset by a reduction of 28 MBoe due to changes in ownership interest. See Note 3 for additional information on acquisitions and divestitures. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month year-end first-day-of-the-month The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2016 2015 2014 Future cash inflows $ 4,434,117 $ 2,851,021 $ 1,167,732 Future production costs (1,220,067 ) (866,253 ) (420,781 ) Future development costs (1,146,632 ) (741,798 ) (147,809 ) Future income tax expense (442,285 ) (216 ) (563 ) Future net cash flows for estimated timing of cash flows 1,625,133 1,242,754 598,579 10% annual discount for estimated timing of cash flows (1,082,092 ) (790,824 ) (368,680 ) Standardized measure of discounted future net cash flows $ 543,041 $ 451,930 $ 229,899 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2016: For the Year Ended December 31, 2016 2015 2014 Beginning of year $ 451,930 $ 229,899 $ 165,181 Balance at inception of common control (February 17, 2015) — 215,544 — Sale of oil and natural gas produced, net of production costs (104,596 ) (60,640 ) (29,498 ) Purchase of minerals in place 188,317 69,258 14,587 Extensions and discoveries 168,796 261,728 20,195 Changes in income taxes, net (206,817 ) 171 (266 ) Changes in prices and costs (57,034 ) (193,130 ) 19,683 Previously estimated development costs incurred 15,067 — 190 Net changes in future development costs 11,985 1,646 (3,194 ) Revisions of previous quantities 3,943 9,827 26,945 Accretion of discount 103,000 41,859 16,522 Change in production rates and other (31,550 ) (124,232 ) (446 ) End of year $ 543,041 $ 451,930 $ 229,899 Capitalized Costs Relating to Oil and Natural Gas Producing Activities The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. For the Year Ended December 31, 2016 2015 2014 Evaluated oil and natural gas properties $ 1,144,857 $ 732,479 $ 247,482 Unevaluated oil and natural gas properties 428,991 251,493 80,058 Accumulated depletion, depreciation and amortization (196,567 ) (117,030 ) (43,539 ) Total $ 1,377,281 $ 866,942 $ 284,001 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2016 2015 2014 Property acquisition costs, proved $ 230,910 $ 92,010 $ 21,337 Property acquisition costs, unproved 235,652 176,832 69,729 Exploration and extension well costs 72,875 132,138 12,731 Development 63,006 107,651 28,253 Total $ 602,443 $ 508,631 $ 132,050

Subsequent Events

Subsequent Events	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 19. Subsequent Events Preferred Stock Dividend—Payment In Kind On July 31, 2017, we announced an aggregate quarterly dividend of $2.175 million on our outstanding shares of Preferred Stock. The dividend was paid by an automatic increase to the accreted value of each such share of Preferred Stock, which were issued with an initial accreted value of $1,000. The dividend is for the period beginning on June 30, 2017 (the issuance date of the Preferred Stock) to July 31, 2017 and was paid to holders of record on July 15, 2017. 2025 Senior Notes Payment On August 1, 2017, we made an interest payment of $12.0 million on our 2025 Senior Notes. Our next payment is due February 1, 2018.	Note 20. Subsequent Events Eagle Ford Acquisitions In February 2017, we announced multiple transactions to acquire certain oil and natural gas producing and non-producing 2025 Senior Notes Offering On February 1, 2017, we completed our private placement of $350 million in aggregate principal amount of our 6.875% Senior Notes due 2025. The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $340.4 million. The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year. We intend to use the net proceeds from the 2025 Senior Notes offering 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 that net cash proceeds from one or more equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest. Registration Rights Agreement 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 Notes. The Company and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods. Option Exercise On January 17, 2017, we also 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.

Preferred Stock

Preferred Stock	6 Months Ended
	Jun. 30, 2017
Temporary Equity Abstract
Preferred Stock	Note 10. Preferred Stock Preferred Stock Issuance On June 30, 2017, we completed the Acquisition, which was partially funded through the issuance of the Preferred Stock. 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. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P., for $435.0 million dollars in exchange for 435,000 shares of Preferred Stock. Series A (in thousands) Balance at December 31, 2016 $ — Issuance of preferred stock in connection with the Acquisition 435,000 Costs incurred related to the issuance of preferred stock (2,416 ) Preferred stock dividends 73 Balance at June 30, 2017 $ 432,657 The Preferred Stock ranks senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up as-converted The Preferred Stock is convertible at the option of the holders at any time after June 30, 2018 into the amount of shares of common stock per share of Preferred Stock (such rate, the “Conversion Rate”) equal to the quotient of (i) the Accreted Value in effect on the conversion date divided by (ii) a conversion price of $13.90 (the “Conversion Price”), subject to customary anti-dilution adjustments and customary provisions related to partial dividend periods. The holders of Preferred Stock may also convert their Preferred Stock at the Conversion Rate prior to June 30, 2018 in connection with certain change of control transactions and in connection with sales of common stock by certain of our existing stockholders. Following June 30, 2021, the Company may cause the conversion of the Preferred Stock at the Conversion Rate, provided the closing sale price of the common stock equals or exceeds 140% of the Conversion Price for the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert and subject to certain other requirements regarding registration of the shares issuable upon conversion. Notwithstanding the foregoing, the Company shall only be permitted to deliver one conversion notice during any 180 day period and the number of shares of common stock issued upon conversion of the Preferred Stock for which such automatic conversion notice is given shall be limited to 25 times the average daily trading volume of our common stock during the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert. If the Company undergoes certain change of control transactions, the holders of the Preferred Stock are entitled to cause the Company to redeem the Preferred Stock for cash in an amount equal to the Accreted Value, plus the net present value of dividend payments that would have been accrued as payable to the holders following the date of the consummation of such change of control and through December 30, 2019, in the case of any change of control occurring prior to December 30, 2019 (the “COC Redemption Price”). In addition, the Company has the right in connection with any such change of control transaction (i) to elect to redeem any Preferred Stock contingent upon and contemporaneously with the consummation of such change of control or (ii) to redeem any Preferred Stock following the consummation of such control that is not otherwise converted or redeemed as described in the preceding sentence and clause (i) of this sentence for cash at the COC Redemption Price. At any time after June 30, 2022, the Company may redeem the Preferred Stock, in whole or in part, for an amount in cash equal to, per each share of Preferred Stock, (i) on or prior to the June 30, 2023, the Accreted Value multiplied by 112%, (ii) on or prior to June 30, 2024, the Accreted Value multiplied by 109% or (ii) after June 30, 2024, the Accreted Value multiplied by 106%. Until conversion, the holders of the Preferred Stock vote together with our common stock on an as-converted as-converted In addition, from and after the Requisite Approvals Notice Date, the Carlyle Investor, as a holder of Preferred Stock is entitled to elect (i) two directors to our board of directors for so long as the Carlyle Investor or its affiliates hold Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing at least 10% of our outstanding common stock on an as-converted as-converted

Organization and Basis of Pre28

Organization and Basis of Presentation (Policies)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Initial Public Offering and Corporate Reorganization		Initial Public Offering and Corporate Reorganization The Company issued and sold to the public in its initial public offering 27,500,000 shares of common stock. The gross proceeds from the sale of the common stock were $412.5 million, net of underwriting discounts of $14.1 million and other offering costs of $5.0 million. The net proceeds from our initial public offering were $393.4 million. Debt issuance costs of $2.9 million related to the establishment of the Company’s revolving credit facility were also incurred in conjunction with our initial public offering. Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation. 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 gas properties owned by us.
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 and six months ended June 30, 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”).	Basis of Presentation Our predecessor’s financial statements were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the financial statements included herein (i) (a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (ii) (a) for the period from January 1, 2015 to February 16, 2015 and (b) for the year ended December 31, 2014, have been derived from the results attributable to our predecessor. Furthermore, the results of Acquisition Co. are reflected in the financial statements presented herein beginning on December 19, 2016. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. 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 to other income. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“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) incentive unit compensation cost; (9) contingent liabilities and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.	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 and gas reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (6) 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.
Cash and Cash Equivalents		Cash and Cash Equivalents We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the Consolidated and Combined Statements of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable. Restricted Cash Restricted cash consists of certificates of deposit in place to collateralize letters of credit. The letters of credit are required as part of normal business operations. The certificates of deposit will be in place for a period greater than 12 months and are considered noncurrent.
Oil and Gas Properties		Oil and Gas Properties We use the successful efforts method of accounting for natural gas and crude oil producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Costs to drill and develop development wells and costs to drill and develop exploratory wells that find proved reserves are also capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed. The following table reflects the net changes in capitalized exploratory well costs for the periods indicated: For Year Ended December 31, 2016 2015 2014 Balance, beginning of period $ 15,198 $ 11,134 $ — Balance at inception of common control — 6,385 — Additions to capitalized exploratory well costs pending the determination of proved reserves 60,847 96,726 11,134 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (68,981 ) (93,052 ) — Capitalized exploratory well costs charged to expense — (5,995 ) — Balance, end of period $ 7,064 $ 15,198 $ 11,134 We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable. We recorded impairment of $3.0 million and $1.2 million as exploration expense for unproved oil and gas properties for the year ended December 31, 2016 and 2015, respectively. We had no leasehold impairment expense for the year ended December 31, 2014. Capitalized costs of producing natural gas and crude oil properties and support equipment, net of estimated salvage values, are depleted by field using the units-of-production Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. We recorded impairment expense of $9.3 million and $24.7 million to proved oil and gas properties for the year ended December 31, 2015 and 2014, respectively. The impairment resulted from lower projected oil and gas prices and a drop in projected remaining reserves in East Texas and our non-core
Oil and Gas Reserves		Oil and Gas Reserves The estimates of proved natural gas, crude oil and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 19—“Supplemental Oil and Gas Information (Unaudited)” for further information.
Gathering System		Gathering System In 2015, our Oakfield subsidiary constructed and began operating a 15.2 mile 16” natural gas gathering system in order to provide sufficient, cost effective access to major markets for our existing and expected future production from new horizontal wells in North Louisiana. The wells are charged a fee for gathering services based on their throughput volumes and gas quality. In 2016, only wells operated by us were connected to the system. We are depreciating the Oakfield gathering assets on a straight-line basis over the current expected reserve life of wells connected to the system.
Other Property and Equipment		Other Property and Equipment Other property and equipment includes our natural gas gathering system, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized.
Capitalized Interest		Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2016, 2015 and 2014, we recorded $0.1 million, $0.8 million $0.2 million in capitalized interest, respectively.
Properties Acquired in Business Combinations		Properties Acquired in Business Combinations Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions and Divestitures.”
Asset Retirement Obligations		Asset Retirement Obligations We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production The fair value of the estimated cost is based on historical experience, managements’ expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated
Environmental Costs		Environmental Costs As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Revenue Recognition and Oil and Gas Imbalances		Revenue Recognition and Oil and Gas Imbalances Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. We receive payment approximately one month after delivery for operated wells and up to three months after delivery for non-operated
Incentive Units		Incentive Units For details regarding incentive units issued by our predecessor, please see “Note 13. Incentive Units.”
Accounts Receivable		Accounts Receivable We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of crude oil, natural gas and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties. Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes two months of accrued revenues for operated properties and three months of accrued revenues for non-operated Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.1 million at both December 31, 2016 and 2015.
Derivative Instruments		Derivative Instruments We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price swaps collars and puts. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales. All derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current
Lease Expenses		Lease Expenses We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis.
Debt Issuance Costs		Debt Issuance Costs Debt issuance costs associated with line-of-credit
Fair Value Measurements		Fair Value Measurements Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements of Financial Instruments.”
Income Taxes		Income Taxes We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carry forwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our Consolidated and Combined Statement of Operations. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.
Commitments and Contingencies		Commitments and Contingencies Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplement cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 306 $ 3,671 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities 82,295 (5,321 )	Supplemental Cash Flow Information Supplement cash flow for the periods presented: For Year Ended December 31, 2016 2015 2014 Supplemental cash flows: Cash paid for interest $ 7,152 $ 7,253 $ 2,515 Noncash investing activities: (Decrease) increase in capital expenditures in accounts payables and accrued liabilities (4,492 ) 349 5,530
New Accounting Standards	New Accounting Standards Improvements to Employee Share-Based Payment Accounting. Leases. right-of-use Revenue from Contracts with Customers. 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.	New Accounting Standards Definition of a Business Statement of Cash Flows—Restricted Cash a consensus of the FASB Emerging Issues Task Force Statement of Cash Flows—Classification of Certain Cash Receipts and Cash Payments Improvements to Employee Share-Based Payment Accounting Leases right-of-use Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently evaluating the standard and the impact on our financial statements and related footnote disclosures. Balance Sheet Classification of Deferred Taxes tax-paying Simplifying the Accounting for Measurement-Period Adjustments Presentation of Debt Issuance Cost line-of-credit line-of-credit line-of-credit Revenue from Contracts with Customers 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 Accoun29

Summary of Significant Accounting Policies (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule of Net changes Capitalized Exploratory Costs		The following table reflects the net changes in capitalized exploratory well costs for the periods indicated: For Year Ended December 31, 2016 2015 2014 Balance, beginning of period $ 15,198 $ 11,134 $ — Balance at inception of common control — 6,385 — Additions to capitalized exploratory well costs pending the determination of proved reserves 60,847 96,726 11,134 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (68,981 ) (93,052 ) — Capitalized exploratory well costs charged to expense — (5,995 ) — Balance, end of period $ 7,064 $ 15,198 $ 11,134
Schedule of Supplemental Cash Flow Information	Supplement cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2017 2016 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 306 $ 3,671 Noncash investing activities: Increase (decrease) in capital expenditures in accounts payables and accrued liabilities 82,295 (5,321 )	Supplement cash flow for the periods presented: For Year Ended December 31, 2016 2015 2014 Supplemental cash flows: Cash paid for interest $ 7,152 $ 7,253 $ 2,515 Noncash investing activities: (Decrease) increase in capital expenditures in accounts payables and accrued liabilities (4,492 ) 349 5,530

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 For the Six Months Ended 2017 2016 2017 2016 $2,199 $ 72 $ 2,798 $ 72	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 Year Ended December 31, 2016 2015 2014 $553 $593 $1,450
Summary of Fair Value of Assets Acquired and Liabilities Assumed	The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing of the Acquisition (in thousands): Consideration: Cash $ 533,609 Common stock 60,754 Total consideration 594,363 Preliminary Purchase Price Allocation: Proved oil and gas properties $ 264,144 Unproved oil and gas properties 333,778 Accounts receivable 967 Asset retirement obligations (2,500 ) Accrued liabilities (2,026 ) Total identifiable net assets $ 594,363 The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands). Purchase Price Oil and 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	The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Preliminary Oil and gas properties $ 396,481 Other property and equipment 478 Accounts receivable 3,160 Asset retirement obligations (3,101 ) Accrued liabilities (7,206 ) Total identifiable net assets $ 389,812 The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Comstock Oil and gas properties $ 102,628 Other property and equipment 500 Asset retirement obligations (112 ) Total identifiable net assets $ 103,016
Summary of Unaudited Pro Forma Financial Information	The following unaudited pro forma combined results of operations are provided for the three months and six months ended June 30, 2017 and 2016 as though the Acquisition had been completed on January 1, 2016 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired in the Acquisition and (ii) depletion expense applied to the adjusted basis of the properties acquired in the Acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Three Months Ended June 30, For the Six Months Ended June 30, 2017 2016 2017 2016 Revenues $ 93,471 $ 55,198 $ 172,674 $ 100,868 Net Income 38,747 (7,674 ) 69,777 (17,510 ) Earnings per share (basic and diluted) 0.41 n/a 0.74 n/a The following unaudited pro forma combined results of operations are provided for the three months and six months ended June 30, 2016 as though the Burleson North Acquisition had been completed on January 1, 2015 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired 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 Burleson North acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Three For the Six Revenues $ 43,393 $ 78,727 Net income (loss) (13,822 ) (28,051 ) Basic and diluted earnings per share n/a n/a	The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 and 2015 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company, the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For Year Ended December 31, 2016 2015 Revenues $ 176,082 $ 172,044 Net income (loss) (34,894 ) (83,894 ) Basic and diluted earnings per unit n/a n/a
November Acquisition And Rosewood Acquisition
Summary of Fair Value of Assets Acquired and Liabilities Assumed		The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date for the November Acquisition and Rosewood Acquisition (in thousands): Rosewood November Oil and gas properties 19,626 29,973

Fair Value Measurements of Fi31

Fair Value Measurements of Financial Instruments (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Fair Value Measurements at June 30, 2017 Using Quoted Prices in Significant Other Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 53,379 $ — $ 53,379 Liabilities: Commodity derivatives $ — $ 1,623 $ — $ 1,623 Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 7 $ — $ 7 Liabilities: Commodity derivatives $ — $ 22,185 $ — $ 22,185	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 7 $ — $ — Liabilities: Commodity derivatives $ — $ 22,185 $ — $ 22,185 Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Fair Value (In thousands) Assets: Commodity derivatives $ — $ 9,764 $ — $ 9,764 Liabilities: Commodity derivatives $ — $ 248 $ — $ 248

Risk Management and Derivativ32

Risk Management and Derivative Instruments (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts	The following derivative contracts were in place at June 30, 2017: Remainder 2017 2018 2019 Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 1,185,971 5,023,163 3,284,623 Weighted-average fixed price $ 52.57 $ 53.29 $ 53.80 Collar contracts: Volume (Bbls) 28,240 25,096 — Weighted-average floor price $ 50.00 $ 50.00 $ — Weighted-average ceiling price $ 62.10 $ 62.10 $ — Put options: Volume (Bbls) 1,215,036 597,850 410,525 Weighted-average floor price $ 55.00 $ 50.00 $ 50.00 Weighted-average put premium $ (4.77 ) $ (5.95 ) $ (5.95 ) Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 4,000,500 11,565,800 9,877,900 Weighted-average fixed price $ 3.12 $ 3.03 $ 2.81 Collar contracts: Volume (MMBtu) 2,760,000 — — Weighted-average floor price $ 3.00 $ — $ — Weighted-average ceiling price $ 3.36 $ — $ — Put options: Volume (MMBtu) 2,971,208 — — Weighted-average floor price $ 3.40 $ — $ — Weighted-average put premium $ (0.37 ) $ — $ —	The following derivative contracts were in place at December 31, 2016: 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Volume (MMBtu) 9,029,600 11,565,800 9,877,900 Weighted-average fixed price $ 3.15 $ 3.03 $ 2.81 Collar contracts: Volume (MMBtu) 5,520,000 — — Weighted-average floor price $ 3.00 $ — $ — Weighted-average ceiling price $ 3.36 $ — $ — Put options: Volume (MMBtu) 1,068,350 — — Weighted-average floor price $ 3.40 $ — $ — Weighted-average put premium $ (0.35 ) $ — $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Volume (Bbls) 2,146,300 1,638,500 1,381,300 Weighted-average fixed price $ 52.90 $ 53.68 $ 54.92 Collar contracts: Volume (Bbls) 60,784 25,096 — Weighted-average floor price $ 50.00 $ 50.00 $ — Weighted-average ceiling price $ 62.10 $ 62.10 $ — Put options: Volume (Bbls) 636,400 — — Weighted-average floor price $ 55.00 $ — $ — Weighted-average put premium $ (4.76 ) $ — $ —
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 June 30, 2017 and December 31, 2016 (in thousands). There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives Type Balance Sheet Location June 30, December 31, June 30, December 31, Commodity contracts Short-term derivative instruments $ 28,543 $ 4 $ 1,173 $ 14,091 Netting arrangements Short-term derivative instruments (351 ) (4 ) (351 ) (4 ) Net recorded fair value $ 28,192 $ — $ 822 $ 14,087 Commodity contacts Long-term derivative instruments $ 24,836 $ 3 $ 450 $ 8,094 Netting arrangements Long-term derivative instruments (401 ) (3 ) (401 ) (3 ) Net recorded fair value $ 24,435 $ — $ 49 $ 8,091	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2016 and 2015. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2016 2015 2016 2015 Commodity contracts Short-term derivative instruments $ 4 $ 7,108 $ 14,091 $ 32 Netting arrangements Short-term derivative instruments (4 ) (32 ) (4 ) (32 ) Net recorded fair value $ — $ 7,076 $ 14,087 $ — Commodity contacts Long-term derivative instruments $ 3 $ 2,656 $ 8,094 $ 216 Netting arrangements Long-term derivative instruments (3 ) (216 ) (3 ) (216 ) Net recorded fair value $ — $ 2,440 $ 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 and six months ending June 30, 2017 and 2016 (in thousands): Statements of Operations Location For the Three Months For the Six Months 2017 2016 2017 2016 Commodity derivative contracts (Gain) loss on derivative instruments $ (46,116 ) $ 15,610 $ (77,407 ) $ 12,364	The following table details the gains and losses related to derivative instruments for the years ending December 31, 2016, 2015 and 2014: Statements of Operations Location For the Year Ended December 31, 2016 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ 26,771 $ (13,854 ) $ (6,514 )

Accounts Receivable (Tables)

Accounts Receivable (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following (in thousands): June 30, 2017 December 31, Oil, natural gas and NGL sales $ 25,437 $ 13,390 Joint interest billings 13,710 7,898 Derivative receivable 1,948 — Severance tax 33 392 Other current receivables 969 4,848 Allowance for doubtful accounts (100 ) (100 ) Total $ 41,997 $ 26,428	Accounts receivable consist of the following: At December 31, 2016 2015 Oil, gas and NGL sales $ 13,390 $ 9,412 Joint interest billings 7,898 3,455 Severance tax 392 531 Other current receivables(1) 4,848 389 Allowance for doubtful accounts (100 ) (50 ) Total $ 26,428 $ 13,737 (1) Primarily relates to a receivable related to our North Burleson Acquisition.
Schedule of Allowance for Doubtful Accounts Activity		The following table presents our allowance for doubtful accounts activity for the periods indicated: For the Year Ended December 31, 2016 2015 2014 Balance at beginning of period $ 50 $ — $ — Charged to costs and expenses 50 50 — Balance at end of period $ 100 $ 50 $ —

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities consist of the following (in thousands): June 30, 2017 December 31, Capital expenditures $ 100,491 $ 17,934 Deferred rent 398 386 Lease operating expense 3,070 2,608 General and administrative 4,377 1,471 Severance and ad valorem taxes 4,678 194 Interest expense 10,043 346 Derivative payable — 428 Other accrued liabilities(1) 2,689 4 Total $ 125,746 $ 23,371 (1) Other accrued liabilities include $1.5 million for seismic acquisition.	Accrued liabilities consist of the following: At December 31, 2016 2015 Capital expenditures $ 17,934 $ 26,105 Deferred rent 386 363 Lease operating expense 2,608 1,459 General and administrative 1,471 242 Severance and ad valorem taxes 194 415 Interest expense 346 192 Other accrued liabilities 432 6 Total $ 23,371 $ 28,782

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2017 (in thousands): Asset retirement obligations at beginning of period $ 11,033 Accretion expense 305 Liabilities incurred 2,698 Revisions (286 ) Asset retirement obligations at end of period 13,751 Less: current portion (90 ) Asset retirement obligations—long-term $ 13,661	The following table presents the changes in the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014: For the Year Ended December 31, 2016 2015 2014 Asset retirement obligations at beginning of period $ 7,020 $ 5,935 $ 4,991 Balance at inception of common control (February 17, 2015) — 37 — Accretion expense 407 354 309 Liabilities incurred 3,723 686 676 Liabilities settled (5 ) (8 ) — Revisions (112 ) 16 (41 ) Asset retirement obligations at end of period 11,033 7,020 5,935 Less: current portion 90 90 90 Asset retirement obligations—long-term $ 10,943 $ 6,930 $ 5,845

Long Term Debt (Tables)

Long Term Debt (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Our debt obligations consisted of the following at the dates indicated (in thousands): Credit Facility June 30, 2017 December 31, WRD revolving credit facility $ 146,000 $ 242,750 2025 Senior Notes (as defined below)(1) 350,000 — Unamortized discounts (2,541 ) — Unamortized debt issuance costs—2025 Senior Notes (8,426 ) — Total long-term debt $ 485,033 $ 242,750 (1) The estimated fair value of this fixed-rate debt was $328.1 million at June 30, 2017. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.	Our debt obligations consisted of the following at the dates indicated: For the Year Ended December 31, Credit Facility 2016 2015 WRD revolving credit facility $ 242,750 $ — WHR II revolving credit facility terminated December 2016 — 118,000 Esquisto—revolving credit facility terminated December 2016 — 50,000 Esquisto—revolving credit facility terminated January 2016 — 40,000 Esquisto—second lien terminated in January 2016 — 30,000 Unamortized debt issuance costs—second lien — (143 ) Total long-term debt $ 242,750 $ 237,857
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 June 30, For the Six Months Ended June 30, Credit Facility 2017 2016 2017 2016 WRD revolving credit facility 3.40 % n/a 3.48 % n/a WHR II revolving credit facility terminated December 2016 n/a 3.00 % n/a 3.00 % Esquisto—revolving credit facility terminated December 2016 n/a 2.80 % n/a 2.81 % Esquisto—revolving credit facility terminated January 2016 n/a n/a n/a 2.97 % Esquisto—Second lien terminated in January 2016 n/a n/a n/a 9.50 %	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 Year Ended December 31, Credit Facility 2016 2015 2014 WRD revolving credit facility 3.52 % n/a n/a WHR II revolving credit facility terminated December 2016 n/a 2.60 % 2.40 % Esquisto—revolving credit facility terminated December 2016 n/a 3.13 % n/a Esquisto—revolving credit facility terminated January 2016 n/a 2.97 % n/a Esquisto—Second lien terminated in January 2016 n/a 9.25 % n/a
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands): June 30, 2017 December 31, WRD revolving credit facility(1) $ 3,966 $ 2,904 6.875% senior unsecured notes, due February 2025 8,426 n/a Total $ 12,392 $ 2,904 (1) We classified $0.9 million and $0.6 million of unamortized deferred financing costs at June 30, 2017 and December 31, 2016, respectively, under current assets as a component of “prepaid expenses and other current assets.”	Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated (dollars in thousands): At December 31, 2016 2015 WRD revolving credit facility $ 2,904 n/a WHR II revolving credit facility terminated December 2016 n/a 581 Esquisto—revolving credit facility terminated December 2016 n/a 494 Esquisto—second lien terminated in January 2016 n/a 143 $ 2,904 $ 1,218
Schedule of Borrowing Base Revolving Credit Facility	The borrowing base for our revolving credit facility was the following at the date indicated (in thousands): June 30, 2017 Credit Facility WRD revolving credit facility $ 650,000

Equity (Tables)

Equity (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Equity [Abstract]
Summary of Changes in Common Shares Issued	The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common stock issued for the six months ended June 30, 2017: Balance, December 31, 2016 91,680,441 Common stock issued 7,815,225 Restricted common stock issued 1,640,351 Balance, June 30, 2017 101,136,017	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 year ended December 31, 2016: Balance, January 1, 2016 — Shares of common stock issued in connection with Corporate Reorganization 62,518,680 Shares of common stock issued in initial public offering 27,500,000 Shares of common stock issued in connection with Rosewood Acquisition 1,308,427 Restricted common shares issued 353,334 Balance, December 31, 2016 91,680,441
Summary Advances and Payments of Promissory Note Advances		The table below summarizes advances and payments of the promissory note advances for the years ended December 31, 2016, 2015 and 2014: Principal Interest Total Balance, December 31, 2013 $ 9,702 $ 97 $ 9,799 Advances 9,403 — 9,403 Payments (17,454 ) (303 ) (17,757 ) Accrued Interest — 245 245 Balance, December 31, 2014 1,651 39 1,690 Advances 1,096 — 1,096 Payments (380 ) (13 ) (393 ) Accrued Interest — 50 50 Balance, December 31, 2015 2,367 76 2,443 Advances 101 — 101 Payments (20 ) — (20 ) Accrued Interest — 51 51 Dissolution (2,448 ) (127 ) (2,575 ) Balance, December 31, 2016 $ — $ — $ —

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 and six months ending June 30, 2017 (in thousands, except per share amounts). In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. For the Three For the Six Numerator: Net income (loss) available to WildHorse Development $ 26,366 $ 46,618 Less: Preferred stock dividends 73 73 Less: Undistributed earnings allocated to participating securities 387 434 Net income (loss) available to common stockholders $ 25,906 $ 46,111 Denominator: Weighted-average common shares outstanding (in thousands)(1) 93,685 93,452 Basic EPS $ 0.28 $ 0.49 Diluted EPS(1) $ 0.28 $ 0.49 (1) The Company used the two-class if-converted	The following sets forth the calculation of earnings (loss) per share, or EPS, for the year ending December 31, 2016 (in thousands, except per share amounts): Numerator: Net income (loss) available to WildHorse Resources $ (10,397 ) Denominator: Weighted-average common shares outstanding (in thousands)(1) 91,327 Basic EPS $ (0.11 ) Diluted EPS(1) $ (0.11 ) (1) The Company determines the more dilutive of either the two-class two-class

Long Term Incentive Plans (Tabl

Long Term Incentive Plans (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based 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 Weighted- Average Grant Restricted common stock outstanding at December 31, 2016 353,334 $ 14.50 Granted(2) 1,640,351 $ 13.94 Restricted common stock outstanding at June 30, 2017 1,993,685 $ 14.04 (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 $22.9 million based on grant date market prices ranging from $13.94 per share to $14.22 per share.	The following table summarizes information regarding restricted common share awards granted under the 2016 LTIP for the periods presented: Number of Weighted- Restricted common shares outstanding at January 1, 2016 $ — $ — Granted(2) 353,334 $ 14.50 Restricted common shares outstanding at December 31, 2016 $ 353,334 $ 14.50 (1) Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards. (2) The aggregate grant date fair value of restricted common share awards granted in 2016 was $5.1 million based on grant date market price of $14.50 per share.

Segment Disclosures (Tables)

Segment Disclosures (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 For the Six Months Ended June 30, 2017 2016 2017 2016 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ 26,366 $ (18,281 ) $ 46,618 $ (32,497 ) Interest expense, net 6,633 1,781 12,204 3,753 Income tax (benefit) expense 15,193 111 26,893 250 Depreciation, depletion and amortization 33,229 19,923 59,672 41,986 Exploration expense 11,504 80 13,119 7,523 (Gain) loss on derivative instruments (46,116 ) 15,610 (77,407 ) 12,364 Cash settlements received (paid) on derivative instruments 2,076 2,525 1,093 5,898 Stock-based compensation 1,308 — 1,803 — Acquisition related costs 2,199 72 2,798 72 Debt extinguishment costs — — (11 ) 358 Public offering costs — — 182 — Non-cash — (103 ) — (286 ) Total Adjusted EBITDAX $ 52,392 $ 21,718 $ 86,964 $ 39,421	The following table presents a reconciliation of net income (loss) to Adjusted EBITDAX: For the Year Ended December 31, 2016 2015 2014 Adjusted EBITDAX reconciliation to net (loss) income: Net income (loss) $ (47,076 ) $ (33,040 ) $ (14,437 ) Interest expense, net 7,834 6,943 2,680 Income tax (benefit) expense (5,575 ) 604 (158 ) Depreciation, depletion and amortization 81,757 56,244 15,297 Exploration expense 12,026 18,299 1,597 Impairment of proved oil and gas properties — 9,312 24,721 (Gain) loss on derivative instruments 26,771 (13,854 ) (6,514 ) Cash settlements received (paid) on derivative instruments 4,975 11,517 (2,712 ) Stock-based compensation 68 — — Acquisition related costs 553 593 1,450 (Gain) loss on sale of properties 43 — — Debt extinguishment costs 1,667 — — Initial public offering costs 1,560 — — Non-cash (286 ) (760 ) (647 ) Total Adjusted EBITDAX $ 84,317 $ 55,858 $ 21,277
Summary of Major Customers		Major Customers Major Customers For the Year Ended December 31, 2016 2015 2014 Energy Transfer Equity, L.P. and subsidiaries 63 % 36 % 10 % Royal Dutch Shell plc and subsidiaries 12 % 20 % 41 % Cima Energy LTD 15 % 16 % n/a BP Corporation North America n/a n/a 31 %

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Components of Income Tax Benefit (Expense)	The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2016 2015 2014 Current income taxes: Federal $ — $ — $ (31 ) State — — — Total income tax benefit (expense) — — (31 ) Deferred income taxes: Federal 5,737 77 156 State (162 ) (681 ) 33 Total deferred income tax benefit (expense) 5,575 (604 ) 189 Total income tax benefit (expense) $ 5,575 $ (604 ) $ 158
Schedule of Effective Income Tax Rate Reconciliation	The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2016 2015 2014 Expected tax benefit (expense) ad federal statutory rate $ 18,428 $ 11,353 $ 5,108 State income tax benefit (expense), net of federal benefit (105 ) (680 ) 32 Pass-through entities(1) (12,499 ) (11,315 ) (5,010 ) Valuation allowance (234 ) — — Other (15 ) 38 28 Total income tax benefit (expense) $ 5,575 $ (604 ) $ 158 (1) Our predecessor was a pass-through entity for federal income tax purposes.
Components of Net Deferred Income Tax Liabilities	The components of net deferred income tax liabilities are as follows: For the Year Ended December 31, 2016 2015 Deferred income tax assets: Tax carryovers $ 2,597 $ 60 Asset retirement obligation 4,083 8 Derivatives 8,184 — Other 870 — Total deferred income tax assets 15,734 68 Valuation allowance 232 — Net deferred income tax assets 15,502 68 Deferred income tax liabilities: Property, plant and equipment 127,835 882 Derivatives — 25 Other 219 13 Total deferred income tax liabilities 128,054 920 Net deferred income tax liabilities 112,552 852

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Minimum Commitments to Transporter	Our minimum commitments to the Transporter as of December 31, 2016 is as follows (in thousands): 2017 2018 2019 $4,380 $4,380 $768
Summmary of Minimum Commitments of Lease Obligations	The table below reflects our minimum commitments as of December 31, 2016: 2017 2018 2019 2020 Thereafter Office Lease $ 1,235 $ 1,259 $ 1,282 $ 1,306 $ 548 Compressor and Equipment 1,599 — — — — Total $ 2,834 $ 1,259 $ 1,282 $ 1,306 $ 548

Quarterly Financial Informati43

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2016 Revenues $ 25,127 $ 29,715 $ 33,239 $ 39,261 Operating income (loss) (15,005 ) (704 ) 1,457 (1,976 ) Net income (loss) (14,216 ) (18,281 ) 3,057 (17,636 ) Net income (loss) allocated to predecessor (11,699 ) (13,016 ) (2,104 ) (7,179 ) Net income (loss) allocated to previous owner (2,517 ) (5,265 ) 5,161 (60 ) Net income (loss) available to common stockholders n/a n/a n/a (10,397 ) Basic earnings per share n/a n/a n/a $ (0.11 ) Diluted earnings per share n/a n/a n/a $ (0.11 ) For the Year Ended December 31, 2015 Revenues $ 11,472 $ 21,238 $ 25,416 $ 28,209 Operating income (loss) (5,334 ) (16,502 ) (7,501 ) (9,863 ) Net income (loss) (4,217 ) (18,649 ) (4,712 ) (5,462 ) Net income (loss) allocated to predecessor (2,653 ) (18,396 ) (4,041 ) (4,865 ) Net income (loss) allocated to previous owner (1,564 ) (253 ) (671 ) (597 )

Supplemental Oil and Gas Info44

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Weighted Average Benchmark Product Prices	All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. For the Year Ended December 31, 2016 2015 2014 Oil ($/Bbl) West Texas Intermediate(1) $ 42.75 $ 46.79 $ 91.48 NGL ($/Bbl) West Texas Intermediate(1) $ 42.75 $ 46.79 $ 91.48 Natural Gas ($/Mmbtu) Henry Hub(2) $ 2.48 $ 2.59 $ 4.35 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
Summary of changes in quantities of proved oil and natural gas reserves	The following tables set forth estimates of the net reserves as of December 31, 2016, 2015 and 2014, respectively: For the Year Ended December 31, 2016 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 36,650 344,959 8,897 103,040 Extensions, discoveries and additions 18,870 32,782 2,606 26,940 Purchase of minerals in place 26,835 13,545 1,823 30,916 Production (1,848 ) (17,820 ) (471 ) (5,289 ) Revision of previous estimates 6,940 (48,364 ) (1,981 ) (3,102 ) End of year 87,447 325,102 10,874 152,505 Proved developed reserves: Beginning of year 7,503 142,990 2,235 33,570 End of year 19,192 145,880 3,765 47,270 Proved undeveloped reserves: Beginning of year 29,147 201,969 6,662 69,470 End of year 68,255 179,222 7,109 105,235 For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 222 249,787 324 42,177 Balance at inception of common control (February 17, 2015) 7,400 6,183 1,637 10,068 Extensions, discoveries and additions 27,598 143,338 5,976 57,464 Purchase of minerals in place 1,972 4,296 710 3,398 Production (968 ) (14,847 ) (351 ) (3,794 ) Revision of previous estimates 426 (43,798 ) 601 (6,273 ) End of year 36,650 344,959 8,897 103,040 Proved developed reserves: Beginning of year 222 122,780 324 21,009 End of year 7,503 142,990 2,235 33,570 Proved undeveloped reserves: Beginning of year — 127,007 — 21,168 End of year 29,147 201,969 6,662 69,470 For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGL (MBbls) Equivalent (MBoe) Proved developed and undeveloped reserves: Beginning of the year 175 210,293 — 35,224 Extensions and discoveries 63 4,318 573 1,356 Purchase of minerals in place 17 13,684 — 2,298 Production (31 ) (9,388 ) (41 ) (1,637 ) Revision of previous estimates (2 ) 30,880 (208 ) 4,936 End of year 222 249,787 324 42,177 Proved developed reserves: Beginning of year 175 97,734 — 16,464 End of year 222 122,780 324 21,009 Proved undeveloped reserves: Beginning of year — 112,559 — 18,760 End of year — 127,007 — 21,168
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2016 2015 2014 Future cash inflows $ 4,434,117 $ 2,851,021 $ 1,167,732 Future production costs (1,220,067 ) (866,253 ) (420,781 ) Future development costs (1,146,632 ) (741,798 ) (147,809 ) Future income tax expense (442,285 ) (216 ) (563 ) Future net cash flows for estimated timing of cash flows 1,625,133 1,242,754 598,579 10% annual discount for estimated timing of cash flows (1,082,092 ) (790,824 ) (368,680 ) Standardized measure of discounted future net cash flows $ 543,041 $ 451,930 $ 229,899
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2016: For the Year Ended December 31, 2016 2015 2014 Beginning of year $ 451,930 $ 229,899 $ 165,181 Balance at inception of common control (February 17, 2015) — 215,544 — Sale of oil and natural gas produced, net of production costs (104,596 ) (60,640 ) (29,498 ) Purchase of minerals in place 188,317 69,258 14,587 Extensions and discoveries 168,796 261,728 20,195 Changes in income taxes, net (206,817 ) 171 (266 ) Changes in prices and costs (57,034 ) (193,130 ) 19,683 Previously estimated development costs incurred 15,067 — 190 Net changes in future development costs 11,985 1,646 (3,194 ) Revisions of previous quantities 3,943 9,827 26,945 Accretion of discount 103,000 41,859 16,522 Change in production rates and other (31,550 ) (124,232 ) (446 ) End of year $ 543,041 $ 451,930 $ 229,899
Capitalized Costs Relating to Oil and Natural Gas Producing Activities	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. For the Year Ended December 31, 2016 2015 2014 Evaluated oil and natural gas properties $ 1,144,857 $ 732,479 $ 247,482 Unevaluated oil and natural gas properties 428,991 251,493 80,058 Accumulated depletion, depreciation and amortization (196,567 ) (117,030 ) (43,539 ) Total $ 1,377,281 $ 866,942 $ 284,001
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2016 2015 2014 Property acquisition costs, proved $ 230,910 $ 92,010 $ 21,337 Property acquisition costs, unproved 235,652 176,832 69,729 Exploration and extension well costs 72,875 132,138 12,731 Development 63,006 107,651 28,253 Total $ 602,443 $ 508,631 $ 132,050

Preferred Stock (Tables)

Preferred Stock (Tables)	6 Months Ended
	Jun. 30, 2017
Temporary Equity Abstract
Schedule of Preferred Stock	Series A (in thousands) Balance at December 31, 2016 $ — Issuance of preferred stock in connection with the Acquisition 435,000 Costs incurred related to the issuance of preferred stock (2,416 ) Preferred stock dividends 73 Balance at June 30, 2017 $ 432,657

Incentive Units (Tables)

Incentive Units (Tables)	6 Months Ended
	Jun. 30, 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 Expected life (years) 1.04 - Expected volatility (range) 54.0% - 62.0% Dividend yield 0.0% Risk-free rate (range) 1.24% - 1.91%

Organization and Basis of Pre47

Organization and Basis of Presentation - Additional Information (Detail) $ in Thousands	Jan. 17, 2017shares	Dec. 31, 2016USD ($)Subsidiaryshares	Jun. 30, 2017Subsidiary
Organization And Basis Of Presentation [Line Items]
Issued and sold of initial public offering | shares	2,297,100	27,500,000
Gross proceeds from the sale of the common stock		$ 412,500
Underwriting Discounts And Commissions		14,100
Other Stock Issuance Costs		5,000
Net proceeds from initial public offering		393,400
Debt issuance cost		$ 2,900
WHR II
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries | Subsidiary		2	2
Esquisto
Organization And Basis Of Presentation [Line Items]
Number of wholly owned subsidiaries | Subsidiary		2	2

Summary of Significant Accoun48

Summary of Significant Accounting Policies - Schedule of Net changes Capitalized Exploratory Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Abstract]
Balance, beginning of period	$ 15,198	$ 11,134
Balance at inception of common control		6,385
Additions to capitalized exploratory well costs pending the determination of proved reserves	60,847	96,726	$ 11,134
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(68,981)	(93,052)
Capitalized exploratory well costs charged to expense		(5,995)
Balance, end of period	$ 7,064	$ 15,198	$ 11,134

Summary of Significant Accoun49

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Exploration expense for unproved oil and gas properties	$ 11,504	$ 80	$ 13,119	$ 7,523	$ 12,026	$ 18,299	$ 1,597
Impairment Expenses						9,312	24,721
Capitalized interest					100	800	200
Provision for uncollectible accounts					100	100
Unproved Oil And Gas Properties
Exploration expense for unproved oil and gas properties					$ 3,000	1,200
Proved Oil And Gas Properties
Impairment Expenses						$ 9,300	$ 24,700

Summary of Significant Accoun50

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 306	$ 3,671	$ 7,152	$ 7,253	$ 2,515
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities	$ 82,295	$ (5,321)	$ (4,492)	$ 349	$ 5,530

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Acquisition-Related Costs Included in General and Administrative Expenses (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Combinations [Abstract]
Acquisition-related costs	$ 2,199	$ 72	$ 2,798	$ 72	$ 553	$ 593	$ 1,450

Acquisitions and Divestitures52

Acquisitions and Divestitures - Additional Information (Detail) $ in Thousands	Jun. 27, 2017USD ($)	Apr. 18, 2017USD ($)	Feb. 02, 2017USD ($)Transactions	Dec. 19, 2016USD ($)ashares	Nov. 08, 2016USD ($)aWells	Jul. 31, 2015USD ($)	Oct. 13, 2014USD ($)	Jun. 03, 2014USD ($)	Feb. 07, 2014USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Jun. 30, 2017USD ($)shares	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Revenues										$ 70,173		$ 39,261	$ 33,239	$ 29,715	$ 25,127	$ 28,209	$ 25,416	$ 21,238	$ 11,472	$ 124,465	$ 54,842	$ 127,342	$ 86,335	$ 45,463
Net loss										26,366		$ (17,636)	$ 3,057	$ (18,281)	$ (14,216)	$ (5,462)	$ (4,712)	$ (18,649)	$ (4,217)	46,618	$ (32,497)	(47,076)	(33,040)	(14,437)
Predecessor
Business Acquisition [Line Items]
Net loss																						$ (33,998)	$ (29,955)	$ (14,437)
Acquisition of oil and natural gas							$ 12,800	$ 37,100	$ 16,000
APC/KKR Acquisitions
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties																				$ 533,609
Business acquisition, date of acquisition agreement																				May 10, 2017
Acquisition of oil and natural gas																				$ 594,363
Business acquisition, date of completion																				Jun. 30, 2017
Business acquisition, aggregate purchase price, value of shares issued										60,754										$ 60,754
APC Subs
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties																				$ 533,600
KKR
Business Acquisition [Line Items]
Business acquisition, aggregate purchase price, shares issued | shares																				5,518,125
Business acquisition, aggregate purchase price, value of shares issued										$ 60,800										$ 60,800
Third Parties Acquisition | Burleson County, TX
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties	$ 2,200	$ 12,500	$ 2,400
Purchase price allocated to unproved oil and natural gas properties	$ 2,200	5,500	$ 2,300
Number of transactions closed as part of acquisition of oil and natural gas producing and non-producing properties | Transactions			1
Purchase price allocated to proved oil and natural gas properties		$ 7,000
Burleson North Acquisition [Member]
Business Acquisition [Line Items]
Area of oil and natural gas properties acquired | a				158,000
Payments to acquire oil and natural gas properties				$ 389,800
Revenues				2,000
Net loss				$ 400
Business acquisition, date of acquisition agreement																						Dec. 19, 2016
Area of oil and natural gas properties acquired | a				158,000
Business acquisition, post-closing receipt											$ 3,900
Burleson North Acquisition [Member] | Preliminary Purchase Price Allocation [Member]
Business Acquisition [Line Items]
Purchase price allocated to unproved oil and natural gas properties				$ 163,800
Burleson North Acquisition [Member] | Final Purchase Price Allocation [Member]
Business Acquisition [Line Items]
Purchase price allocated to unproved oil and natural gas properties				$ 162,900
Rosewood Acquisition
Business Acquisition [Line Items]
Area of oil and natural gas properties acquired | a				7,500
Purchase price allocated to unproved oil and natural gas properties				$ 18,300
Business acquisition, date of acquisition agreement																						Dec. 19, 2016
Business acquisition, aggregate purchase price, shares issued | shares				1,308,427
Comstock Acquisition
Business Acquisition [Line Items]
Payments to acquire oil and natural gas properties						$ 103,000
November Acquisition
Business Acquisition [Line Items]
Area of oil and natural gas properties acquired | a					4,900
Payments to acquire oil and natural gas properties					$ 30,000
Purchase price allocated to unproved oil and natural gas properties					$ 29,400
Business acquisition, date of acquisition agreement																						Nov. 8, 2016
Number of oil and Gas producing wells | Wells					9

Acquisitions and Divestitures53

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands	Dec. 19, 2016	Nov. 08, 2016	Jul. 31, 2015	Jun. 30, 2017
Comstock Acquisition
Consideration:
Cash, Purchase price			$ 103,000
Comstock Acquisition | Final Purchase Price Allocation [Member]
Purchase Price Allocation:
Oil and gas properties			102,628
Other property and equipment			500
Asset retirement obligations			(112)
Total identifiable net assets			$ 103,016
APC/KKR Acquisitions
Consideration:
Cash, Purchase price				$ 533,609
Common stock, Purchase price				60,754
Total consideration, Purchase price				594,363
Purchase Price Allocation:
Proved oil and gas properties, Purchase price				264,144
Unproved oil and gas properties, Purchase price				333,778
Accounts receivable, Purchase Price				967
Asset retirement obligations				(2,500)
Accrued liabilities, Purchase Price				(2,026)
Total identifiable net assets				$ 594,363
Burleson North Acquisition [Member]
Consideration:
Cash, Purchase price	$ 389,800
Burleson North Acquisition [Member] | Preliminary Purchase Price Allocation [Member]
Purchase Price Allocation:
Oil and gas properties	396,481
Other property and equipment	478
Accounts receivable, Purchase Price	3,160
Asset retirement obligations	(3,101)
Accrued liabilities, Purchase Price	(7,206)
Total identifiable net assets	389,812
Burleson North Acquisition [Member] | Final Purchase Price Allocation [Member]
Purchase Price Allocation:
Oil and gas properties	395,591
Other property and equipment	478
Accounts receivable, Purchase Price	1,257
Accounts payable, Purchase Price	(1,816)
Asset retirement obligations	(3,101)
Accrued liabilities, Purchase Price	(6,503)
Total identifiable net assets	385,906
November Acquisition
Consideration:
Cash, Purchase price		$ 30,000
Purchase Price Allocation:
Oil and gas properties		$ 29,973
Rosewood Acquisition
Purchase Price Allocation:
Oil and gas properties	$ 19,626

Acquisitions and Divestitures54

Acquisitions and Divestitures - Summary of Unaudited Pro Forma Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
APC/KKR Acquisitions
Business Acquisition [Line Items]
Revenues	$ 93,471	$ 55,198	$ 172,674	$ 100,868
Net income (loss)	$ 38,747	(7,674)	$ 69,777	(17,510)
Earnings per share (basic and diluted)	$ 0.41		$ 0.74
Burleson North Acquisition [Member]
Business Acquisition [Line Items]
Revenues		43,393		78,727	$ 176,082	$ 172,044
Net income (loss)		$ (13,822)		$ (28,051)	$ (34,894)	$ (83,894)

Fair Value Measurements of Fi55

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value Measurements Recurring - Commodity Derivatives - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Assets:
Fair value of derivative asset	$ 53,379	$ 7	$ 9,764
Liabilities:
Fair value of derivative liability	1,623	22,185	248
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	53,379	7	9,764
Liabilities:
Fair value of derivative liability	$ 1,623	$ 22,185	$ 248

Fair Value Measurements of Fi56

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties						$ 9,312,000	$ 24,721,000
Proved Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 0	$ 0	$ 0	$ 0	$ 0	$ 9,300,000	$ 24,700,000
Unproved Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 10,000,000	$ 100,000	$ 10,700,000	$ 100,000

Risk Management and Derivativ57

Risk Management and Derivative Instruments - Schedule of Derivative Contracts (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2017MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2016MMBTU$ / bbl$ / MMBTUbbl
Crude Oil Derivative Contracts Fixed Price Swap Remainder 2017
Derivative [Line Items]
Volume (Bbls) | bbl	1,185,971	2,146,300
Weighted-average fixed price	52.57	52.90
Crude Oil Derivative Contracts Collar Remainder 2017
Derivative [Line Items]
Volume (Bbls) | bbl	28,240	60,784
Weighted-average floor price	50	50
Weighted-average ceiling price	62.10	62.10
Crude Oil Derivative Contracts Put Options Remainder 2017
Derivative [Line Items]
Volume (Bbls) | bbl	1,215,036	636,400
Weighted-average floor price	55	55
Weighted-average put premium	(4.77)	(4.76)
Natural Gas Derivative Contracts Fixed Price Swap Remainder 2017
Derivative [Line Items]
Volume (MMBtu) | MMBTU	4,000,500	9,029,600
Weighted-average fixed price | $ / MMBTU	3.12	3.15
Natural Gas Derivative Contracts Collar Remainder 2017
Derivative [Line Items]
Volume (MMBtu) | MMBTU	2,760,000	5,520,000
Weighted-average floor price	3	3
Weighted-average ceiling price	3.36	3.36
Natural Gas Derivative Contracts Put Options Remainder 2017
Derivative [Line Items]
Volume (MMBtu) | MMBTU	2,971,208	1,068,350
Weighted-average floor price	3.40	3.40
Weighted-average put premium	(0.37)	(0.35)
Crude Oil Derivative Contracts Fixed Price Swap 2018
Derivative [Line Items]
Volume (Bbls) | bbl	5,023,163	1,638,500
Weighted-average fixed price	53.29	53.68
Crude Oil Derivative Contracts Collar 2018
Derivative [Line Items]
Volume (Bbls) | bbl	25,096	25,096
Weighted-average floor price	50	50
Weighted-average ceiling price	62.10	62.10
Natural Gas Derivative Contracts Fixed Price Swap 2018
Derivative [Line Items]
Volume (MMBtu) | MMBTU	11,565,800	11,565,800
Weighted-average fixed price | $ / MMBTU	3.03	3.03
Crude Oil Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (Bbls) | bbl	3,284,623	1,381,300
Weighted-average fixed price	53.80	54.92
Natural Gas Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (MMBtu) | MMBTU	9,877,900	9,877,900
Weighted-average fixed price | $ / MMBTU	2.81	2.81
Crude Oil Derivative Contracts Put Options 2019
Derivative [Line Items]
Volume (Bbls) | bbl	410,525
Weighted-average floor price	50
Weighted-average put premium	(5.95)
Crude Oil Derivative Contracts Put Options 2018
Derivative [Line Items]
Volume (Bbls) | bbl	597,850
Weighted-average floor price	50
Weighted-average put premium	(5.95)

Risk Management and Derivativ58

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($)	3 Months Ended	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash collateral received or pledged	$ 0	$ 0	$ 0	$ 0
Deferred premiums	500,000	600,000
Derivative asset	51,800,000	51,800,000
Derivative asset, right to offset amount	$ 43,700,000	43,700,000
Reduction in maximum credit exposure		$ 8,100,000

Risk Management and Derivativ59

Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Asset Derivatives, Net recorded fair value	$ 51,800
Short-term Derivative Instruments | Commodity Derivatives
Derivative [Line Items]
Asset Derivatives, Gross fair value	28,543	$ 4	$ 7,108
Asset Derivatives, Netting arrangements	(351)	(4)	(32)
Asset Derivatives, Net recorded fair value	28,192		7,076
Liability Derivatives, Gross fair value	1,173	14,091	32
Liability Derivatives, Netting arrangements	(351)	(4)	(32)
Liability Derivatives, Net recorded fair value	822	14,087
Long-term Derivative Instruments | Commodity Derivatives
Derivative [Line Items]
Asset Derivatives, Gross fair value	24,836	3	2,656
Asset Derivatives, Netting arrangements	(401)	(3)	(216)
Asset Derivatives, Net recorded fair value	24,435		2,440
Liability Derivatives, Gross fair value	450	8,094	216
Liability Derivatives, Netting arrangements	(401)	(3)	$ (216)
Liability Derivatives, Net recorded fair value	$ 49	$ 8,091

Risk Management and Derivativ60

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, (Gain) Loss [Line Items]
(Gain) loss on derivative instruments	$ (46,116)	$ 15,610	$ (77,407)	$ 12,364	$ 26,771	$ (13,854)	$ (6,514)
Commodity Derivatives
Derivative Instruments, (Gain) Loss [Line Items]
(Gain) loss on derivative instruments	$ (46,116)	$ 15,610	$ (77,407)	$ 12,364	$ 26,771	$ (13,854)	$ (6,514)

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 25,437	$ 13,390	$ 9,412
Joint interest billings	13,710	7,898	3,455
Derivative receivable	1,948
Severance tax	33	392	531
Other current receivables	969	4,848	389
Allowance for doubtful accounts	(100)	(100)	(50)
Total	$ 41,997	$ 26,428	$ 13,737

Accounts Receivable - Schedul62

Accounts Receivable - Schedule of Accounts Notes Loans and Financing Receivable (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Balance at beginning of period	$ 50
Charged to costs and expenses	50	$ 50
Balance at end of period	$ 100	$ 50

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Payables and Accruals [Abstract]
Capital expenditures	$ 100,491	$ 17,934	$ 26,105
Deferred rent	398	386	363
Lease operating expense	3,070	2,608	1,459
General and administrative	4,377	1,471	242
Severance and ad valorem taxes	4,678	194	415
Interest expense	10,043	346	192
Derivative payable		428
Other accrued liabilities including derivative payable		432	6
Other accrued liabilities	2,689	4
Total	$ 125,746	$ 23,371	$ 28,782

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 11,033	$ 7,020	$ 7,020	$ 5,935	$ 4,991
Balance at inception of common control (February 17, 2015)				37
Accretion expense	305	$ 198	407	354	309
Liabilities incurred	2,698		3,723	686	676
Liabilities settled			(5)	(8)
Revisions	(286)		(112)	16	(41)
Asset retirement obligations at end of period	13,751		11,033	7,020	5,935
Less: current portion	90		90	90	90
Asset retirement obligations-long-term	$ 13,661		$ 10,943	$ 6,930	$ 5,845

Long Term Debt - Schedule of De

Long Term Debt - Schedule of Debt Obligations (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (12,392)	$ (2,904)	$ (1,218)
Total long-term debt	485,033	242,750	237,857
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Long-term debt, gross	350,000
Unamortized discounts	(2,541)
Unamortized debt issuance costs	(8,426)
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	146,000	242,750
Unamortized debt issuance costs	$ (3,966)	$ (2,904)
WHR II Revolving Credit Facility Terminated December 2016
Debt Instrument [Line Items]
Long-term debt, gross			118,000
Esquisto-Revolving Credit Facility Terminated December 2016
Debt Instrument [Line Items]
Long-term debt, gross			50,000
Esquisto-Revolving Credit Facility Terminated January 2016
Debt Instrument [Line Items]
Long-term debt, gross			40,000
Esquisto-Second Lien Terminated In January 2016
Debt Instrument [Line Items]
Long-term debt, gross			30,000
Unamortized debt issuance costs			$ (143)

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Detail) - USD ($)	Feb. 01, 2017	Dec. 19, 2016	Jun. 30, 2017	Dec. 31, 2016	Apr. 27, 2017
Debt Instrument [Line Items]
Proceeds from senior notes offering			$ 347,354,000
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
Issue price of notes as a percentage of par value	99.244%
6.875% Senior Unsecured Notes, Due February 2025 | Private Placement
Debt Instrument [Line Items]
Aggregate principal amount	$ 350,000,000
Debt instrument interest rate percentage	6.875%
Debt instrument maturity date			Feb. 1, 2025
Borrowing base reduced amount	$ 87,500,000
Issue price of notes as a percentage of par value	99.244%
Proceeds from senior notes offering	$ 338,600,000
Debt instrument redemption price percentage	106.875%
Debt instrument, redemption description			We may redeem all or any part of the 2025 Senior Notes at a "make-whole" redemption price, plus accrued and unpaid interest, at any time before February 1, 2020. We may also redeem up to 35% of the aggregate principal amount of the 2025 Senior Notes prior to February 1, 2020 in an amount not greater than the net cash proceeds from one or more equity offerings at a redemption price of 106.875% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest.
Minimum
Debt Instrument [Line Items]
Amount of borrowing base and elected commitment			$ 450,000,000
Aggregate principal amount			50,000,000
Maximum
Debt Instrument [Line Items]
Amount of borrowing base and elected commitment			650,000,000
Aggregate principal amount			75,000,000
Maximum | 6.875% Senior Unsecured Notes, Due February 2025 | Private Placement
Debt Instrument [Line Items]
Debt instrument redemption percentage of principal amount	35.00%
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit expiration period		5 years
Line of credit maximum borrowing capacity		$ 1,000,000,000
Amount of borrowing base and elected commitment	$ 362,500,000	$ 450,000,000	$ 650,000,000
Debt issuance date				Dec. 19, 2016
Secured Credit Facility, discount rate		9.00%
Interest description				Borrowings under our revolving credit facility will bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies from 1.25% to 2.25% per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.
WRD Revolving Credit Facility | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Interest rate spread				0.50%
WRD Revolving Credit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Interest rate spread				1.00%
WRD Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Secured Credit Facility lien percentage		85.00%
Commitment fee percentage				0.375%
Ratio of current assets to current liabilities				1
WRD Revolving Credit Facility | Minimum | Adjusted LIBOR
Debt Instrument [Line Items]
Libor Margin				1.25%
WRD Revolving Credit Facility | Minimum | Applicable Market Indexed London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Libor Margin				2.25%
WRD Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Commitment fee percentage				0.50%
Ratio of total debt to EBITDAX				400.00%
WRD Revolving Credit Facility | Maximum | Adjusted LIBOR
Debt Instrument [Line Items]
Libor Margin				2.25%
WRD Revolving Credit Facility | Maximum | Applicable Market Indexed London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Libor Margin				3.25%
WRD Revolving Credit Facility | Standby Letters of Credit | Railroad Commission Of Texas
Debt Instrument [Line Items]
Letters of Credit Outstanding					$ 1,900,000
WRD Revolving Credit Facility | Certain Properties Prior to February 2, 2017 | Minimum
Debt Instrument [Line Items]
Secured Credit Facility lien percentage		75.00%

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	3.40%		3.48%		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%		3.00%		2.60%	2.40%
Esquisto-Revolving Credit Facility Terminated December 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.80%		2.81%		3.13%
Esquisto-Revolving Credit Facility Terminated January 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				2.97%		2.97%
Esquisto-Second Lien Terminated In January 2016
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				9.50%		9.25%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 12,392	$ 2,904	$ 1,218
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument [Line Items]
Unamortized deferred financing costs	8,426
WHR II Revolving Credit Facility Terminated December 2016
Debt Instrument [Line Items]
Unamortized deferred financing costs			581
Esquisto-Revolving Credit Facility Terminated December 2016
Debt Instrument [Line Items]
Unamortized deferred financing costs			494
Esquisto-Revolving Credit Facility Terminated January 2016
Debt Instrument [Line Items]
Unamortized deferred financing costs			$ 143
WRD Revolving Credit Facility
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 3,966	$ 2,904

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	Jan. 17, 2017	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	May 31, 2015	Feb. 17, 2015
Class of Stock [Line Items]
Common stock, shares authorized		500,000,000			500,000,000
Common stock, par value		$ 0.01			$ 0.01
Preferred stock, par value					$ 0.01
Shares of preferred stock					50,000,000
Preferred Stock, Shares Issued					0
Preferred stock outstanding					0
Capital contribution					$ 107,837	$ 334,226	$ 89,437
Common stock issued	2,297,100				27,500,000
Common stock offering price	$ 15
Proceeds from exercise of over-allotment	$ 32,600
Previous owner capital contributions			$ 25,000		$ 97,000	208,376
Capital contributions received from members			$ 13,280		13,280	125,098	97,546
KKR
Class of Stock [Line Items]
Stock issued during period shares, acquisitions		5,518,125
Stock issued during period value, acquisitions		$ 60,800
Previous Owner
Class of Stock [Line Items]
Capital contribution				$ 208,376	97,000
Property contribution				$ 40,100
Excess of investment cost over book value acquired								$ 26,600	$ 16,100
Predecessor
Class of Stock [Line Items]
Capital contribution					$ 10,837	$ 125,850	$ 89,437
Promissory note advances to fund future capital commitments and carried an interest rate					2.50%
Common Stock
Class of Stock [Line Items]
Common stock issued	2,297,100	7,815,225			27,500,000

Equity - Summary of Changes in

Equity - Summary of Changes in Common Shares Issued (Detail) - shares	Jan. 17, 2017	Jun. 30, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Common stock issued	2,297,100		27,500,000
Common Stock
Class of Stock [Line Items]
Balance at the beginning of the period		91,680,441
Shares of common stock issued in connection with Corporate Reorganization			62,518,680
Common stock issued	2,297,100	7,815,225	27,500,000
Shares of common stock issued in connection with Rosewood Acquisition			1,308,427
Restricted common shares issued		1,640,351	353,334
Balance at the end of the period		101,136,017	91,680,441

Equity - Summary of Advances an

Equity - Summary of Advances and Payments of Promissory Note Advances (Detail) - Predecessor - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Beginning balance	$ 2,443	$ 1,690	$ 9,799
Advances	101	1,096	9,403
Payments	(20)	(393)	(17,757)
Accrued Interest	51	50	245
Dissolution	(2,575)
Ending balance		2,443	1,690
Principal
Class of Stock [Line Items]
Beginning balance	2,367	1,651	9,702
Advances	101	1,096	9,403
Payments	(20)	(380)	(17,454)
Dissolution	(2,448)
Ending balance		2,367	1,651
Interest
Class of Stock [Line Items]
Beginning balance	76	39	97
Payments		(13)	(303)
Accrued Interest	51	50	245
Dissolution	$ (127)
Ending balance		$ 76	$ 39

Earnings per share - Schedule o

Earnings per share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2017	Dec. 31, 2016
Numerator:
Net income (loss) available to WildHorse Development	$ 26,366		$ 46,618	$ (10,397)
Less: Preferred stock dividends	73		73
Less: Undistributed earnings allocated to participating securities	387		434
Net income (loss) available to common stockholders	$ 25,906	$ (10,397)	$ 46,111	$ (10,397)
Denominator:
Weighted-average common shares outstanding	93,685		93,452	91,327
Basic EPS	$ 0.28	$ (0.11)	$ 0.49	$ (0.11)
Diluted EPS	$ 0.28	$ (0.11)	$ 0.49	$ (0.11)

Earnings per share - Schedule73

Earnings per share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Parenthetical) (Detail) - shares shares in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Incremental shares excluded in calculation of diluted EPS	344	173	363
Restricted Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Incremental shares excluded in calculation of diluted EPS	455	308

Long Term Incentive Plans - Add

Long Term Incentive Plans - Additional Information (Detail) - 2016 Long-Term Incentive Plan - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock authorized for issuance under plan	9,512,500	9,512,500	9,512,500
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock Granted for issuance under plan		1,640,351	353,334
Recognized compensation expense	$ 1.3	$ 1.8	$ 0.1
Unrecognized compensation cost	$ 26.1	$ 26.1	$ 5
Unrecognized compensation cost, weighted-average period		2 years 9 months 26 days	2 years 10 months 10 days

Long Term Incentive Plans - Sum

Long Term Incentive Plans - Summary of Restricted Common Stock Awards Granted Under 2016 LTIP (Detail) - 2016 Long-Term Incentive Plan - Restricted Stock - $ / shares	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Number of Shares
Restricted common stock outstanding, beginning balance	353,334
Restricted commons shares, Granted	1,640,351	353,334
Restricted common stock outstanding, ending balance	1,993,685	353,334
Weighted Average Grant Date Fair Value per Share
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, beginning balance	$ 14.50
Restricted common shares, Granted, Weighted-Average Grant Date Fair Value per Share	13.94	$ 14.50
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, ending balance	$ 14.04	$ 14.50

Long Term Incentive Plans - S76

Long Term Incentive Plans - Summary of Restricted Common Stock Awards Granted Under 2016 LTIP (Parenthetical) (Detail) - 2016 Long-Term Incentive Plan - USD ($) $ / shares in Units, $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$ 22,900	$ 5,100
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 13.94	$ 14.50
Restricted Stock | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	13.94
Restricted Stock | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 14.22

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Incentive Unit Valuation Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of internal rate of return		5.00%
Recognized compensation expense	$ 0
Unrecognized compensation costs associated with incentive units	$ 21,700,000
WHR II | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive units, maximum range		20.00%
WHR II | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive units, maximum range		40.00%

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail)	Jun. 18, 2014USD ($)	Jun. 30, 2017USD ($)shares	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)shares	Jun. 30, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2016USD ($)Directorsshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Related Party Transaction [Line Items]
Initial offering lock-up period							180 days
Anticipated aggregate common stock offering price							$ 30,000,000
Predecessor
Related Party Transaction [Line Items]
Debt instrument interest rate percentage							2.50%
Debt instrument, accrued interest							$ 51	$ 50	$ 245
NGP X US Holdings
Related Party Transaction [Line Items]
Payment made to related party initial public offering expenses							800,000
NGP X US Holdings | Predecessor
Related Party Transaction [Line Items]
Payments made for director fees							$ 100,000	100,000	100,000
Multi-Shot, LLC
Related Party Transaction [Line Items]
Payments made to related party								100,000	100,000
WHR II
Related Party Transaction [Line Items]
Common stock shares issued related to reorganization transactions | shares							21,200,084
Esquisto
Related Party Transaction [Line Items]
Common stock shares issued related to reorganization transactions | shares							38,755,330
Notes payable to related party, owed						$ 6,400,000		6,400,000
Debt instrument maturity date							Dec. 31, 2022
Esquisto | General and Administrative
Related Party Transaction [Line Items]
Notes payable to related party			$ 1,100,000		$ 2,100,000	3,600,000	$ 4,000,000
Esquisto | Drilling and Producing Wells
Related Party Transaction [Line Items]
Payments made to related party			300,000		600,000	900,000	$ 1,300,000
Acquisitions [Member]
Related Party Transaction [Line Items]
Common stock shares issued related to reorganization transactions | shares							2,563,266
Carlyle Group, L.P.
Related Party Transaction [Line Items]
Preferred stock, shares issued | shares		435,000		435,000
Carlyle Group, L.P. | NGP ECM
Related Party Transaction [Line Items]
Percentage of ownership interest in certain gross revenues		55.00%		55.00%
Genesis Energy Partners, L.P
Related Party Transaction [Line Items]
Proceeds from sale		$ 600,000		$ 1,500,000			$ 2,800,000
NGP ECM | Maximum
Related Party Transaction [Line Items]
Payments made to related party		$ 100,000		$ 100,000			100,000
NGP ECM | Predecessor | Maximum
Related Party Transaction [Line Items]
Payments made to related party			100,000		100,000
NGP ECM | Carlyle Group, L.P. | NGP X US Holdings
Related Party Transaction [Line Items]
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds		40.00%		40.00%
NGP ECM | Carlyle Group, L.P. | NGP XI
Related Party Transaction [Line Items]
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds		47.50%		47.50%
Non Officer Employees [Member]
Related Party Transaction [Line Items]
Payments made to related party							100,000	100,000	100,000
Highmark Energy Operating L L C | Non-operated Working Interests in Oil and Natural Gas Properties
Related Party Transaction [Line Items]
Net payments received from related parties			100,000		200,000		200,000	400,000	100,000
Highmark Energy Operating L L C | Non-operated Working Interests in Oil and Natural Gas Properties | Maximum
Related Party Transaction [Line Items]
Related party payments or receipts		$ 100,000		$ (100,000)
Cretic Energy Services, LLC | Drilling and Completion Activities
Related Party Transaction [Line Items]
Payments made to related party			300,000		400,000		400,000	1,000,000	6,500,000
Related party payments or receipts		$ 100,000		$ 100,000
PennTex Midstream Partners, LP
Related Party Transaction [Line Items]
Proceeds from sale								100,000	100,000
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		$ 100,000		200,000
WHR II
Related Party Transaction [Line Items]
Payments made to related party							5,000,000
Proceeds from sale								$ 1,600,000
WHR II | Promissory Notes
Related Party Transaction [Line Items]
Debt instrument interest rate percentage			2.50%		2.50%
Debt instrument, accrued interest					$ 100,000
WildHorse Resources Management Company, LLC [Member]
Related Party Transaction [Line Items]
Payments made to related party									$ 6,000,000
Wild Horse Resources L L C
Related Party Transaction [Line Items]
Payments made to related party	$ 57,600,000						$ 100,000
Payments made to related party	200,000
Proceeds from sale	$ 53,000,000
Wild Horse Resources L L C | Non-operated Working Interests in Oil and Natural Gas Properties | Maximum
Related Party Transaction [Line Items]
Payments made to related party			$ 100,000		100,000
Wild Horse Resources L L C | Esquisto | Director [Member]
Related Party Transaction [Line Items]
Board of Directors nominees | Directors							1
Wild Horse Resources L L C | Esquisto | NGP X US Holdings
Related Party Transaction [Line Items]
Common stock outstanding shares							15.00%
Petromax Operating Company, Inc. | Chief Operating Officer of Esquisto
Related Party Transaction [Line Items]
Percentage of ownership		33.30%		33.30%			33.30%
Calbri Energy, Inc. | Esquisto | Completion Consulting Services
Related Party Transaction [Line Items]
Payments made to related party			$ 100,000		$ 200,000	$ 400,000	$ 400,000
Calbri Energy, Inc. | Esquisto | Completion Consulting Services | Maximum
Related Party Transaction [Line Items]
Percentage of ownership			1.00%		1.00%	1.00%		1.00%
CH4 Energy
Related Party Transaction [Line Items]
Payments made to related party		$ 300,000
Related party payments or receipts			$ 0		$ 0
CH4 Energy | Maximum
Related Party Transaction [Line Items]
Payments made to related party				$ 100,000
CH4 Energy | Esquisto
Related Party Transaction [Line Items]
Payments made to related party							3,600,000
Garland Exploration LLC | Non-operated Working Interests in Oil and Natural Gas Properties
Related Party Transaction [Line Items]
Net payments received from related parties		300,000	$ 0	300,000	$ 0
Garland Exploration LLC | Esquisto
Related Party Transaction [Line Items]
Payments made to related party							5,500,000
Crossing Rocks Energy LLC. | Esquisto
Related Party Transaction [Line Items]
Payments made to related party							$ 1,300,000
Service Providers | Maximum
Related Party Transaction [Line Items]
Payments made to related party		$ 100,000		$ 100,000

Segment Disclosures - Additiona

Segment Disclosures - Additional Information (Detail) - Segment	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Segment Reporting [Abstract]
Number of operating segments	2	2
Number of reportable segments	1	1

Segment Disclosures - Reconcili

Segment Disclosures - Reconciliation of Net Income (Loss) to Adjusted EBITDAX (Detail) - USD ($) $ in Thousands	3 Months Ended									6 Months Ended		12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$ 26,366	$ (17,636)	$ 3,057	$ (18,281)	$ (14,216)	$ (5,462)	$ (4,712)	$ (18,649)	$ (4,217)	$ 46,618	$ (32,497)	$ (47,076)	$ (33,040)	$ (14,437)
Interest expense, net	6,633			1,781						12,204	3,753	7,834	6,943	2,680
Income tax (benefit) expense	15,193			111						26,893	250	(5,575)	604	(158)
Depreciation, depletion and amortization	33,229			19,923						59,672	41,986	81,757	56,244	15,297
Exploration expense	11,504			80						13,119	7,523	12,026	18,299	1,597
Impairment of proved oil and gas properties													9,312	24,721
(Gain) loss on derivative instruments	(46,116)			15,610						(77,407)	12,364	26,771	(13,854)	(6,514)
Cash settlements received (paid) on derivative instruments	2,076			2,525						1,093	5,898	4,975	11,517	(2,712)
Stock-based compensation	1,308									1,803		68
Acquisition related costs	2,199			72						2,798	72	553	593	1,450
(Gain) loss on sale of properties												43
Debt extinguishment costs										(11)	358	1,667
Public offering costs										182		1,560
Non-cash liability amortization				(103)							(286)	(286)	(760)	(647)
Total Adjusted EBITDAX	$ 52,392			$ 21,718						$ 86,964	$ 39,421	$ 84,317	$ 55,858	$ 21,277

Segment Disclosures - Major Cus

Segment Disclosures - Major Customers (Detail) - Customer Concentration Risk - Sales Revenue, Segment [Member]	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Energy Transfer Equity LP. and subsidiaries.
Concentration risk percentage	63.00%	36.00%	10.00%
Royal Dutch Shell Plc and Subsidiaries.
Concentration risk percentage	12.00%	20.00%	41.00%
Cima Energy Ltd.
Concentration risk percentage	15.00%	16.00%
BP Corporation North America.
Concentration risk percentage			31.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Expense) (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current income taxes:
Federal							$ (31)
State					$ 0	$ 0	0
Total income tax benefit (expense)							(31)
Deferred income taxes:
Federal					5,737	77	156
State					(162)	(681)	33
Total deferred income tax benefit (expense)			$ (26,893)	$ (230)	5,575	(604)	189
Total income tax benefit (expense)	$ (15,193)	$ (111)	$ (26,893)	$ (250)	$ 5,575	$ (604)	$ 158

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income tax expense benefit continuing operations income tax reconciliation
Expected tax benefit (expense) ad federal statutory rate					$ 18,428	$ 11,353	$ 5,108
State income tax benefit (expense), net of federal benefit					(105)	(680)	32
Pass-through entities					(12,499)	(11,315)	(5,010)
Valuation allowance					(234)
Other					(15)	38	28
Total income tax benefit (expense)	$ (15,193)	$ (111)	$ (26,893)	$ (250)	$ 5,575	$ (604)	$ 158

Income Taxes - Components of Ne

Income Taxes - Components of Net Deferred Income Tax Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax assets:
Tax carryovers	$ 2,597	$ 60
Asset retirement obligation	4,083	8
Derivatives	8,184
Other	870
Total deferred income tax assets	15,734	68
Valuation allowance	232
Net deferred income tax assets	15,502	68
Deferred income tax liabilities:
Property, plant and equipment	127,835	882
Derivatives		25
Other	219	13
Total deferred income tax liabilities	128,054	920
Net deferred income tax liabilities	$ 112,552	$ 852

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred tax liabilities					$ 128,054,000	$ 920,000
Liability for unrecognized tax benefits	$ 0		$ 0		$ 0
Income tax operating loss carry forward expiration year					Dec. 31, 2036
Valuation allowance					$ 232,000
Income tax (benefit) expense	$ 15,193,000	$ 111,000	$ 26,893,000	$ 250,000	(5,575,000)	$ 604,000	$ (158,000)
Effective tax rate	36.60%	0.00%	36.60%	0.00%
Significant change to unrecognized tax benefits in next twelve months	$ 0		$ 0
IPO And Related Restructuring Transactions [Member]
Income Tax Disclosure [Abstract]
Deferred tax liabilities					117,300,000
Domestic Tax Authority [Member]
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward					6,500,000
State and Local Jurisdiction [Member]
Income Tax Disclosure [Abstract]
Income tax operating loss carry forward					$ 2,000,000

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	Jun. 01, 2017USD ($)Stage	Mar. 15, 2017USD ($)Stage	Jun. 30, 2017USD ($)Agreementacre ft	Dec. 31, 2016USD ($)MMBTU	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Commitments And Contingencies [Line Items]
Quantities Transporter per day | MMBTU				40,000
Average annual lease payment between July 2014 and May 2021				$ 1,200,000
Compressor and equipment rental agreement latest expiration date				Mar. 31, 2017
Accrued liability for existing and potential claims			$ 0	$ 0
Environmental obligations recognized			0	0
Restricted cash			$ 752,000	886,000	$ 551,000
Interruptible water availability agreement, start date			Feb. 1, 2017
Interruptible water availability agreement, end date			Dec. 31, 2021
Compressor and Equipment [Member]
Commitments And Contingencies [Line Items]
Rent Expense				600,000	1,000,000	$ 700,000
General and Administrative
Commitments And Contingencies [Line Items]
Rent Expense				900,000	$ 800,000	$ 400,000
Maximum
Commitments And Contingencies [Line Items]
Daily transportation fees				0.30
Dedicated Fracturing Fleet Services Agreements
Commitments And Contingencies [Line Items]
Number of agreements entered for completion of wells and drilling operations | Agreement			2
Fixed monthly service fee for cost of equipment and personnel	$ 2,800,000	$ 2,700,000
Additional term of agreement for completion of wells and drilling operations	12 months	12 months
Term of agreement for completion of wells and drilling operations	23 months	20 months
Minimum number of stages to be completed for milestone payments | Stage	115	360
Percentage of amount payable in excess of chemicals and fuel cost	10.00%	10.00%
Early termination fee, description			approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on the termination date.
Early termination fee, approximate multiplier to number of months remaining under initial contract term	$ 1,400,000	$ 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			$ 800,000	$ 900,000

Schedule of Future Minimum Comm

Schedule of Future Minimum Commitemet (Detail) $ in Thousands	Dec. 31, 2016USD ($)
Commitments and Contingencies Disclosure [Abstract]
Contractual obligation to transporter, 2017	$ 4,380
Contractual obligation to transporter, 2018	4,380
Contractual obligation to transporter, 2019	$ 768

Schedule of Future Minimum Leas

Schedule of Future Minimum Lease obligation (Detail) $ in Thousands	Dec. 31, 2016USD ($)
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due 2017	$ 2,834
Operating Leases, Future Minimum Payments, Due 2018	1,259
Operating Leases, Future Minimum Payments, Due 2019	1,282
Operating Leases, Future Minimum Payments, Due 2020	1,306
Operating Leases, Future Minimum Payments, Due Thereafter	548
Office Lease [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due 2017	1,235
Operating Leases, Future Minimum Payments, Due 2018	1,259
Operating Leases, Future Minimum Payments, Due 2019	1,282
Operating Leases, Future Minimum Payments, Due 2020	1,306
Operating Leases, Future Minimum Payments, Due Thereafter	548
Compressor and Equipment [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Due 2017	$ 1,599

Quarterly Financial accounting

Quarterly Financial accounting (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									6 Months Ended		12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Data [Line Items]
Revenues	$ 70,173	$ 39,261	$ 33,239	$ 29,715	$ 25,127	$ 28,209	$ 25,416	$ 21,238	$ 11,472	$ 124,465	$ 54,842	$ 127,342	$ 86,335	$ 45,463
Operating income (loss)	2,078	(1,976)	1,457	(705)	(15,005)	(9,863)	(7,501)	(16,502)	(5,334)	8,284	(15,710)	(16,228)	(39,200)	(18,642)
Net income (loss)	26,366	(17,636)	3,057	(18,281)	(14,216)	(5,462)	(4,712)	(18,649)	(4,217)	46,618	(32,497)	(47,076)	(33,040)	(14,437)
Net income (loss) allocated to predecessor		(7,179)	(2,104)	(13,016)	(11,699)	(4,865)	(4,041)	(18,396)	(2,653)		(24,715)	(33,998)	(29,955)	$ (14,437)
Net income (loss) allocated to previous owner		(60)	$ 5,161	(5,265)	$ (2,517)	$ (597)	$ (671)	$ (253)	$ (1,564)		$ (7,782)	(2,681)	$ (3,085)
Net income (loss) available to common stockholders	$ 25,906	$ (10,397)								$ 46,111		$ (10,397)
Basic earnings per share	$ 0.28	$ (0.11)								$ 0.49		$ (0.11)
Diluted earnings per share	$ 0.28	$ (0.11)								$ 0.49		$ (0.11)
Scenario, Previously Reported [Member]
Quarterly Financial Data [Line Items]
Operating income (loss)				$ (704)

Supplemental Oil and Gas Info90

Supplemental Oil and Gas Information - Proved Reserves, Prices (Detail)		12 Months Ended
		Dec. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2015$ / bbl$ / MMBTU	Dec. 31, 2014$ / bbl$ / MMBTU
Oil [Member]
Price of oil and gas	[1]	42.75	46.79	91.48
Natural Gas Liquids [Member]
Price of oil and gas	[1]	42.75	46.79	91.48
Natural Gas [Member]
Price of oil and gas | $ / MMBTU	[2]	2.48	2.59	4.35
[1]	The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.
[2]	The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

Supplemental Oil and Gas Info91

Supplemental Oil and Gas Information - Estimates of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2016MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls
Reserve Quantities [Line Items]
Beginning of the year | MBoe	103,040	42,177	35,224
Balance at inception of common control (February 17, 2015) | MBoe		10,068
Extensions and discoveries | MBoe	26,940	57,464	1,356
Purchase of minerals in place | MBoe	30,916	3,398	2,298
Production | MBoe	(5,289)	(3,794)	(1,637)
Revision of previous estimates | MBoe	(3,102)	(6,273)	4,936
End of year | MBoe	152,505	103,040	42,177
Proved developed reserves, Beginning of year | MBoe	33,570	21,009	16,464
Proved developed reserves, End of year | MBoe	47,270	33,570	21,009
Proved undeveloped reserves, Beginning of year | MBoe	69,470	21,168	18,760
Proved undeveloped reserves, End of year | MBoe	105,235	69,470	21,168
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning of the year	8,897	324
Balance at inception of common control (February 17, 2015)		1,637
Extensions and discoveries	2,606	5,976	573
Purchase of minerals in place	1,823	710
Production	(471)	(351)	(41)
Revision of previous estimates	(1,981)	601	(208)
End of year	10,874	8,897	324
Proved developed reserves, Beginning of year	2,235	324
Proved developed reserves, End of year	3,765	2,235	324
Proved undeveloped reserves, Beginning of year	6,662
Proved undeveloped reserves, End of year	7,109	6,662
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of the year | MMcf	344,959	249,787	210,293
Balance at inception of common control (February 17, 2015) | MMcf		6,183
Extensions and discoveries | MMcf	32,782	143,338	4,318
Purchase of minerals in place | MMcf	13,545	4,296	13,684
Production | MMcf	(17,820)	(14,847)	(9,388)
Revision of previous estimates | MMcf	(48,364)	(43,798)	30,880
End of year | MMcf	325,102	344,959	249,787
Proved developed reserves, Beginning of year | MMcf	142,990	122,780	97,734
Proved developed reserves, End of year | MMcf	145,880	142,990	122,780
Proved undeveloped reserves, Beginning of year | MMcf	201,969	127,007	112,559
Proved undeveloped reserves, End of year | MMcf	179,222	201,969	127,007
Oil [Member]
Reserve Quantities [Line Items]
Beginning of the year	36,650	222	175
Balance at inception of common control (February 17, 2015)		7,400
Extensions and discoveries	18,870	27,598	63
Purchase of minerals in place	26,835	1,972	17
Production	(1,848)	(968)	(31)
Revision of previous estimates	6,940	426	(2)
End of year	87,447	36,650	222
Proved developed reserves, Beginning of year	7,503	222	175
Proved developed reserves, End of year	19,192	7,503	222
Proved undeveloped reserves, Beginning of year	29,147
Proved undeveloped reserves, End of year	68,255	29,147

Supplemental Oil and Gas Info92

Supplemental Oil and Gas Information - Estimates of Net Reserves (Parenthetical) (Detail) - MBoe	10 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reserve Quantities [Line Items]
Extensions, discoveries and additions		26,940	57,464	1,356
Purchase of minerals in place		30,916	3,398	2,298
Revision of previous estimates		(3,102)	(6,273)	4,936
Commodity Price Changes [Member]
Reserve Quantities [Line Items]
Revision of previous estimates		(711)
Performance Related [Member]
Reserve Quantities [Line Items]
Revision of previous estimates		(2,391)
Commodity Price Change [Member]
Reserve Quantities [Line Items]
Revision of previous estimates	(139)
RCT field in Louisiana [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions		4,131
Eagle Ford [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions	36,583	22,809
Revision of previous estimates	1,315
East Texas [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions				1,356
Predecessor
Reserve Quantities [Line Items]
Purchase of minerals in place		2,298
Revision of previous estimates			(7,450)	4,937
Predecessor | Commodity Price Changes [Member]
Reserve Quantities [Line Items]
Revision of previous estimates				517
Predecessor | Commodity Price Change [Member]
Reserve Quantities [Line Items]
Revision of previous estimates			(3,410)
Predecessor | Technical Changes [Member]
Reserve Quantities [Line Items]
Revision of previous estimates			(4,040)
Predecessor | Gas Processing [Member]
Reserve Quantities [Line Items]
Revision of previous estimates				3,043
Predecessor | Lease Operating Expense Reductions [Member]
Reserve Quantities [Line Items]
Revision of previous estimates				1,405
Predecessor | Changes in Ownership Interest [Member]
Reserve Quantities [Line Items]
Revision of previous estimates				(28)
Predecessor | RCT field in Louisiana [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and additions			20,881
Purchase of minerals in place		410
Predecessor | East Texas [Member]
Reserve Quantities [Line Items]
Purchase of minerals in place		1,888
Previous Owner
Reserve Quantities [Line Items]
Purchase of minerals in place	3,398
Burleson North Acquisition [Member]
Reserve Quantities [Line Items]
Purchase of minerals in place		30,916

Supplemental Oil and Gas Info93

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Additional Information Necessary to Prevent Disclosure of Discounts Future Net Cash Flows from Being Misleading	As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-monthaverage prices, year-endcosts and legislated tax rates and a discount factor of 10 percent to proved reserves.

Supplemental Oil and Gas Info94

Supplemental Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 4,434,117	$ 2,851,021	$ 1,167,732
Future production costs	(1,220,067)	(866,253)	(420,781)
Future development costs	(1,146,632)	(741,798)	(147,809)
Future income tax expense	(442,285)	(216)	(563)
Future net cash flows for estimated timing of cash flows	1,625,133	1,242,754	598,579
10% annual discount for estimated timing of cash flows	(1,082,092)	(790,824)	(368,680)
Standardized measure of discounted future net cash flows	$ 543,041	$ 451,930	$ 229,899	$ 165,181

Supplemental Oil and Gas Info95

Supplemental Oil and Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Beginning of year	$ 451,930	$ 229,899	$ 165,181
Balance at inception of common control (February 17, 2015)		215,544
Sale of oil and natural gas produced, net of production costs	(104,596)	(60,640)	(29,498)
Purchase of minerals in place	188,317	69,258	14,587
Extensions and discoveries	168,796	261,728	20,195
Changes in income taxes, net	(206,817)	171	(266)
Changes in prices and costs	(57,034)	(193,130)	19,683
Previously estimated development costs incurred	15,067		190
Net changes in future development costs	11,985	1,646	(3,194)
Revisions of previous quantities	3,943	9,827	26,945
Accretion of discount	103,000	41,859	16,522
Change in production rates and other	(31,550)	(124,232)	(446)
End of year	$ 543,041	$ 451,930	$ 229,899

Supplemental Oil and Gas Info96

Supplemental Oil and Gas Information - Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Accumulated depletion, depreciation and amortization	$ (196,567)	$ (117,030)	$ (43,539)
Total	1,377,281	866,942	284,001
Evaluated [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties	1,144,857	732,479	247,482
Unevaluated [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties	$ 428,991	$ 251,493	$ 80,058

Supplemental Oil and Gas Info97

Supplemental Oil and Gas Information - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property acquisition costs, proved	$ 230,910	$ 92,010	$ 21,337
Property acquisition costs, unproved	235,652	176,832	69,729
Exploration and extension well costs	72,875	132,138	12,731
Development	63,006	107,651	28,253
Total	$ 602,443	$ 508,631	$ 132,050

Subsequent Events - Additional

Subsequent Events - Additional information (Detail) - USD ($) $ / shares in Units, $ in Thousands	Aug. 01, 2017	Jul. 31, 2017	Feb. 01, 2017	Jan. 17, 2017	Feb. 28, 2017	Dec. 31, 2016	Dec. 31, 2016
Subsequent Event [Line Items]
Acquisition of oil and natural gas					$ 15,600
Shares of common stock issued				2,297,100			27,500,000
Shares of common stock issued, offering price				$ 15
Net proceeds from option exercise				$ 32,600
6.875% Senior Unsecured Notes, Due February 2025
Subsequent Event [Line Items]
Aggregate principal amount			$ 350,000
Senior notes issued, stated percentage			6.875%
Senior notes issued, issue price of as a percentage of par			99.244%
Net proceeds from private placement			$ 340,400
6.875% Senior Unsecured Notes, Due February 2025 | Prior to February 1, 2020 [Member]
Subsequent Event [Line Items]
Percentage of aggregate principal amount that may be redeemed						35.00%
Redemption price						106.875%
Subsequent Event | Preferred Stock | Dividend Payment In Kind
Subsequent Event [Line Items]
Quarterly dividend announced date		Jul. 31, 2017
Quarterly dividend, amount		$ 2,175
Dividend, initial accreted value		$ 1,000,000
Dividend, record date		Jul. 15, 2017
Subsequent Event | 6.875% Senior Unsecured Notes, Due February 2025
Subsequent Event [Line Items]
Interest payment	$ 12,000

Accrued Liabilities - Schedul99

Accrued Liabilities - Schedule of Accrued Liabilities (Parenthetical) (Detail) $ in Millions	Jun. 30, 2017USD ($)
Payables and Accruals [Abstract]
Accrued liabilities, for seismic acquisition	$ 1.5

Long Term Debt - Schedule of100

Long Term Debt - Schedule of Debt Obligations (Parenthetical) (Detail) - 6.875% Senior Unsecured Notes, Due February 2025 $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)
Debt Instrument [Line Items]
Debt instrument maturity period	Feb. 1, 2025
Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Debt Instrument [Line Items]
Estimated fair value of fixed rate debt	$ 328.1

Long Term Debt - Schedule of Bo

Long Term Debt - Schedule of Borrowing Base Revolving Credit Facility (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Feb. 01, 2017	Dec. 19, 2016
WRD Revolving Credit Facility
Line Of Credit Facility [Line Items]
WRD revolving credit facility	$ 650,000	$ 362,500	$ 450,000

Long Term Debt - Summary of 102

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 12,392	$ 2,904	$ 1,218
Prepaid Expenses and Other Current Assets
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 900	$ 600

Preferred Stock - Additional In

Preferred Stock - Additional Information (Detail) $ / shares in Units, $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)Director$ / sharesshares
Temporary Equity [Line Items]
Proceeds from the issuance of preferred stock | $	$ 435,000
Convertible preferred stock, shares issued | shares	435,000
Preferred Stock Purchase Agreement | Carlyle | 10% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Number of directors entitled to be elected upon holding of outstanding common stock | Director	2
Preferred Stock Purchase Agreement | Carlyle | 5% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Number of directors entitled to be elected upon holding of outstanding common stock | Director	1
Preferred Stock Purchase Agreement | Minimum | Carlyle | 10% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Holding percentage of outstanding common stock to elect director	10.00%
Preferred Stock Purchase Agreement | Minimum | Carlyle | 5% Ownership of Outstanding Common Stock
Temporary Equity [Line Items]
Holding percentage of outstanding common stock to elect director	5.00%
Preferred Stock Purchase Agreement | Preferred Stock
Temporary Equity [Line Items]
Proceeds from the issuance of preferred stock | $	$ 435,000
Convertible preferred stock, shares issued | shares	435,000
Business acquisition, date of completion	Jun. 30, 2017
Preferred stock purchase agreement date	May 10, 2017
Preferred equity, initial accreted value, per share | $ / shares	$ 1,000
Preferred stock, dividend rate percentage	6.00%
Preferred Stock Purchase Agreement | Preferred Stock | December 30, 2019 Anniversary
Temporary Equity [Line Items]
Convertible preferred stock, terms of conversion	The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.
Preferred Stock Purchase Agreement | Preferred Stock | June 30, 2018 Anniversary
Temporary Equity [Line Items]
Conversion of stock, conversion price | $ / shares	$ 13.90
Preferred Stock Purchase Agreement | Preferred Stock | June 30, 2021 Anniversary
Temporary Equity [Line Items]
Number of trading days required for conversion	20 days
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 the date immediately prior to the date of delivery of the Company’s notice to convert and subject to certain other requirements regarding registration of the shares issuable upon conversion. Notwithstanding the foregoing, the Company shall only be permitted to deliver one conversion notice during any 180 day period and the number of shares of common stock issued upon conversion of the Preferred Stock for which such automatic conversion notice is given shall be limited to 25 times the average daily trading volume of our common stock during the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert.
Preferred Stock Purchase Agreement | Preferred Stock | June 30, 2023 Anniversary
Temporary Equity [Line Items]
Multiple percentage on preferred stock accreted value	112.00%
Preferred Stock Purchase Agreement | Preferred Stock | June 30, 2024 Anniversary
Temporary Equity [Line Items]
Multiple percentage on preferred stock accreted value	109.00%
Preferred Stock Purchase Agreement | Preferred Stock | After June 30, 2024 Anniversary
Temporary Equity [Line Items]
Multiple percentage on preferred stock accreted value	106.00%
Preferred Stock Purchase Agreement | Preferred Stock | Minimum
Temporary Equity [Line Items]
Preferred stock redemption date	Jun. 30, 2022
Preferred Stock Purchase Agreement | Preferred Stock | Minimum | December 30, 2019 Anniversary
Temporary Equity [Line Items]
Percentage of preferred stock conversion price	130.00%
Number of trading days required for conversion	25 days
Preferred Stock Purchase Agreement | Preferred Stock | Minimum | June 30, 2021 Anniversary
Temporary Equity [Line Items]
Percentage of preferred stock conversion price	140.00%

Preferred Stock - Schedule of P

Preferred Stock - Schedule of Preferred Stock (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)
Class of Stock [Line Items]
Balance at June 30, 2017	$ 432,657
Preferred Stock Purchase Agreement | Preferred Stock
Class of Stock [Line Items]
Issuance of preferred stock in connection with the Acquisition	435,000
Costs incurred related to the issuance of preferred stock	(2,416)
Preferred stock dividends	73
Balance at June 30, 2017	$ 432,657

Incentive Units - Schedule of K

Incentive Units - Schedule of Key Assumptions Used to Estimate Fair Value of Incentive Units (Detail) - Incentive Unit Valuation Tranche One	6 Months Ended
	Jun. 30, 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 15 days
Expected volatility (range)	54.00%
Risk-free rate (range)	1.24%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected life (years)	5 years 3 months 15 days
Expected volatility (range)	62.00%
Risk-free rate (range)	1.91%