Permian Resources (PR) 10-K 23 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Mar. 07, 2017	Jun. 30, 2016
Document And Entity Information [Line Items]
Entity Registrant Name	Centennial Resource Development, Inc.
Entity Central Index Key	1,658,566
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 488,726
Common Class A
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		201,882,082
Common Class B
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		0
Common Class C
Document And Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		19,155,921

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Current assets
Cash and cash equivalents	$ 134,083
Accounts receivable, net	14,734
Derivative instruments, net	431
Prepaid and other current assets	2,078
Total current assets	151,326
Oil and natural gas properties, other property and equipment
Oil and natural gas properties, successful efforts method	605,853
Accumulated depreciation, depletion and amortization	(14,436)
Unproved oil and natural gas properties	1,905,661
Other property and equipment, net of accumulated depreciation of $391 and $868, respectively	2,193
Total property and equipment, net	2,499,271
Noncurrent assets
Derivative instruments, net	0
Other noncurrent assets	1,045
Total assets	2,651,642
Current liabilities
Accounts payable and accrued expenses	86,100
Derivative instruments, net	5,361
Other current liabilities	0
Total current liabilities	91,461
Noncurrent liabilities
Revolving credit facility	0
Term loan, net of unamortized deferred financing costs	0
Asset retirement obligations	7,226
Deferred tax liability	0
Derivative instruments, net	20
Total liabilities	98,707
Stockholders'/Owners' Equity
Additional paid-in capital	2,364,049
Accumulated deficit	(8,929)
Total shareholders’/owners’ equity	2,355,142
Total shareholders’/owners’ equity	0
Noncontrolling interest	197,793
Total equity	2,552,935
Total liabilities and shareholders’/owners’ equity	2,651,642
Predecessor
Current assets
Cash and cash equivalents		$ 1,768
Accounts receivable, net		13,012
Derivative instruments, net		19,043
Prepaid and other current assets		322
Total current assets		34,145
Oil and natural gas properties, other property and equipment
Oil and natural gas properties, successful efforts method		651,596
Accumulated depreciation, depletion and amortization		(180,946)
Unproved oil and natural gas properties		105,897
Other property and equipment, net of accumulated depreciation of $391 and $868, respectively		2,240
Total property and equipment, net		578,787
Noncurrent assets
Derivative instruments, net		2,070
Other noncurrent assets		1,293
Total assets		616,295
Current liabilities
Accounts payable and accrued expenses		19,985
Derivative instruments, net		0
Other current liabilities		2,148
Total current liabilities		22,133
Noncurrent liabilities
Revolving credit facility		74,000
Term loan, net of unamortized deferred financing costs		64,649
Asset retirement obligations		2,288
Deferred tax liability		2,361
Derivative instruments, net		0
Total liabilities		165,431
Stockholders'/Owners' Equity
Accumulated deficit		0
Total shareholders’/owners’ equity		450,864
Noncontrolling interest		0
Total equity		450,864
Total liabilities and shareholders’/owners’ equity		$ 616,295
Series A Preferred Stock | Successor
Stockholders'/Owners' Equity
Preferred stock, $.0001 par value, 1,000,000 shares authorized:	0
Series B Preferred Stock | Successor
Stockholders'/Owners' Equity
Preferred stock, $.0001 par value, 1,000,000 shares authorized:	0
Common Class A | Successor
Stockholders'/Owners' Equity
Common stock, $0.0001 par value, 620,000,000 shares authorized:	20
Common Class C | Successor
Stockholders'/Owners' Equity
Common stock, $0.0001 par value, 620,000,000 shares authorized:	$ 2

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Accumulated depreciation	$ 391
Preferred stock, par value (in dollars per share)	$ 0.0001
Preferred stock, shares authorized (in shares)	1,000,000
Common stock, par value (in dollars per share)	$ 0.0001
Common stock, shares authorized (in shares)	620,000,000
Predecessor
Accumulated depreciation		$ 868
Series A Preferred Stock | Successor
Preferred stock, shares authorized (in shares)	1
Preferred stock, shares issued (in shares)	1
Preferred stock, shares outstanding (in shares)	1
Series B Preferred Stock | Successor
Preferred stock, shares authorized (in shares)	104,400
Preferred stock, shares issued (in shares)	104,400
Preferred stock, shares outstanding (in shares)	104,400
Common Class A | Successor
Common stock, shares authorized (in shares)	600,000,000
Common stock, shares issued (in shares)	201,091,646
Common stock, shares outstanding (in shares)	201,091,646
Common Class C | Successor
Common stock, shares authorized (in shares)	20,000,000
Common stock, shares issued (in shares)	19,155,921
Common stock, shares outstanding (in shares)	19,155,921

Consolidated and Combined State

Consolidated and Combined Statements of Operations - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Revenues
Oil sales	$ 24,313
Natural gas sales	3,449
NGL sales	1,955
Total revenues	29,717
Operating expenses
Lease operating expenses	3,541
Severance and ad valorem taxes	1,636
Transportation, processing, gathering and other operating expense	2,187
Depreciation, depletion, amortization and accretion of asset retirement obligations	14,877
Abandonment expense and impairment of unproved properties	0
Exploration	844
Contract termination and rig stacking	0
General and administrative expenses	13,715
Incentive unit compensation	0
Total operating expenses	36,800
Gain (loss) on sale of oil and natural gas properties	24
Total operating loss	(7,059)
Other (expense) income
Interest expense	(378)
Gain (loss) on derivative instruments	(1,548)
Other (expense) income	0
Total other (expense) income	(1,926)
(Loss) income before income taxes	(8,985)
Income tax benefit (expense)	0
Net (loss) income	(8,985)
Less net loss attributable to noncontrolling interest	(904)
Net (loss) income attributable to Centennial Resource Development, Inc.	$ (8,081)
Loss per share:
Loss per share, basic (in dollars per share)	$ (0.05)
Loss per share, diluted (in dollars per share)	$ (0.05)
Predecessor
Revenues
Oil sales		$ 59,787	$ 77,643	$ 114,955
Natural gas sales		6,045	7,965	9,670
NGL sales		3,284	4,852	7,200
Total revenues		69,116	90,460	131,825
Operating expenses
Lease operating expenses		11,036	21,173	17,690
Severance and ad valorem taxes		3,696	5,021	6,875
Transportation, processing, gathering and other operating expense		4,583	5,732	4,772
Depreciation, depletion, amortization and accretion of asset retirement obligations		62,964	90,084	69,110
Abandonment expense and impairment of unproved properties		2,545	7,619	20,025
Exploration		0	84	0
Contract termination and rig stacking		0	2,387	0
General and administrative expenses		25,581	14,206	31,694
Incentive unit compensation		165,394	0	0
Total operating expenses		275,799	146,306	150,166
Gain (loss) on sale of oil and natural gas properties		11	2,439	(2,096)
Total operating loss		(206,672)	(53,407)	(20,437)
Other (expense) income
Interest expense		(5,626)	(6,266)	(2,475)
Gain (loss) on derivative instruments		(6,838)	20,756	41,943
Other (expense) income		6	20	281
Total other (expense) income		(12,458)	14,510	39,749
(Loss) income before income taxes		(219,130)	(38,897)	19,312
Income tax benefit (expense)		406	572	(1,524)
Net (loss) income		(218,724)	(38,325)	17,788
Less net loss attributable to noncontrolling interest		0	0	(2)
Net (loss) income attributable to Centennial Resource Development, Inc.		$ (218,724)	$ (38,325)	$ 17,790

Consolidated and Combined Stat5

Consolidated and Combined Statements of Changes in Owners' and Shareholders' Equity Statement - USD ($) $ in Thousands	Total	Paid-In Capital	Accumulated Deficit	Total Equity	Noncontrolling Interest	Class A	Class ACommon Stock	Class APaid-In Capital	Class ATotal Equity	Class BCommon Stock	Class C	Class CCommon Stock	Series A	Series APreferred Stock	Series B	Series BPreferred Stock	Series BPaid-In Capital	Series BTotal Equity	Conversion of common shares from Class B to Class A at transactionClass ACommon Stock	Conversion of common shares from Class B to Class A at transactionClass BCommon Stock	Reclassification from Temporary Equity to Permanent Equity [Member]Class ACommon Stock	Conversion of common shares from Class C to Class APaid-In Capital	Conversion of common shares from Class C to Class ATotal Equity	Conversion of common shares from Class C to Class ANoncontrolling Interest	Conversion of common shares from Class C to Class AClass ACommon Stock	Conversion of common shares from Class C to Class AClass CCommon Stock
Balance, beginning of period (Predecessor) at Dec. 31, 2013	$ 390,547			$ 389,859	$ 688
Increase (Decrease) in Partners' Capital [Roll Forward]
Deemed contributions | Predecessor	59,926			59,776	150
Repurchase of equity interests | Predecessor	(119,272)			(119,272)	0
Deemed contribution from sale of assets | Predecessor	20,653			21,489	(836)
Deemed contribution from parent for payment of incentive units | Predecessor	12,420			12,420	0
Deemed distribution | Predecessor	(4,130)			(4,130)	0
Net income (loss) | Predecessor	17,788			17,790	(2)
Balance, end of period (Predecessor) at Dec. 31, 2014	377,932			377,932	0
Increase (Decrease) in Partners' Capital [Roll Forward]
Deemed contributions | Predecessor	111,396			111,396	0
Deemed distribution | Predecessor	(139)			(139)	0
Net income (loss) | Predecessor	(38,325)			(38,325)	0
Balance, end of period (Predecessor) at Dec. 31, 2015	450,864			450,864	0
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss) | Predecessor	(218,724)			(218,724)	0
Balance, end of period (Predecessor) at Oct. 10, 2016	411,582			411,582	0
Balance, end of period (Successor) at Oct. 10, 2016	5,000	$ 5,460	$ (461)	5,000	0		$ 0					$ 0		$ 0		$ 0
Balance, end of period at Oct. 10, 2016										$ 1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common stock, shares outstanding (in shares) | Successor							2,175,208			12,500,000		0
Preferred stock, shares outstanding (in shares) | Successor														0		0
Net income (loss) | Successor	(387)		(387)	(387)
Conversion of common shares (in shares) | Successor																			12,500,000	(12,500,000)	47,825,000				844,079	(844,079)
Conversion of common shares | Successor																			$ 1			$ 7,798	$ 7,798	$ (7,798)
Conversion of common shares																				$ (1)
Class A common shares released from possible redemption | Successor	478,248	478,243		478,248			$ 5
Stock issued during period (in shares) | Successor							101,005,000					20,000,000		1
Stock issued during period | Successor		(2)				$ 1,010,050	$ 10	$ 1,010,040	$ 1,010,050			$ 2
Underwriters’ discount and offering expense | Successor	(6,713)	(6,713)		(6,713)
Noncontrolling interest in Centennial Resource Production, LLC | Successor	184,779				184,779
Balance, end of period (Successor) at Oct. 11, 2016	1,670,977	1,494,826	(848)	1,493,996	176,981		16					2		$ 0		$ 0
Balance, end of period at Oct. 11, 2016										$ 0
Balance, beginning of period (Predecessor) at Oct. 10, 2016	411,582			411,582	0
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss) | Successor	(8,985)		(8,081)	(8,081)	904
Balance, end of period (Successor) at Dec. 31, 2016	0
Balance, beginning of period (Successor) at Oct. 10, 2016	5,000	5,460	(461)	5,000	0		$ 0					0		0		$ 0
Balance, beginning of period at Oct. 10, 2016										1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock issued (in shares) | Successor							256,597
Stock issued during period (in shares) | Successor							36,485,970									104,400
Stock issued during period | Successor						$ 530,507	$ 4	$ 530,503	$ 530,507						$ 379,494		$ 379,494	$ 379,494
Underwriters’ discount and offering expense | Successor	(20,391)	(20,391)		(20,391)
Change in equity due to issuance of shares by Centennial Resource Production, LLC | Successor	0	(21,716)		(21,716)	21,716
Equity based compensation | Successor	1,333	1,333		1,333
Balance, end of period (Successor) at Dec. 31, 2016	$ 2,552,935	$ 2,364,049	$ (8,929)	$ 2,355,142	$ 197,793		$ 20					$ 2		$ 0		$ 0
Balance, end of period at Dec. 31, 2016										$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common stock, shares outstanding (in shares) | Successor							164,349,079			0		19,155,921
Preferred stock, shares outstanding (in shares) | Successor														1		0
Common stock, shares outstanding (in shares) | Successor						201,091,646	201,091,646			0	19,155,921	19,155,921
Preferred stock, shares outstanding (in shares) | Successor													1	1	104,400	104,400

Consolidated and Combined Stat6

Consolidated and Combined Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Net (loss) income	$ (8,985)
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion of asset retirement obligations	49
Depreciation, depletion and amortization	14,828
Equity based compensation expense	1,333
Incentive unit compensation	0
Noncash transaction costs	0
Abandonment expense and impairment of unproved properties	0
Write-off of deferred S-1 related expense	0
Deferred tax (benefit) expense	0
(Gain) loss on sale of oil and natural gas properties	(24)
Loss (gain) on derivative instruments	1,548
Net cash received for derivative settlements	1,054
Recovery of bad debt	0
Amortization of debt issuance costs	70
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	(983)
Increase in prepaid and other assets	(1,092)
Increase (decrease) in accounts payable and other liabilities	1,612
Net cash provided by operating activities	9,410
Cash flows from investing activities:
Proceeds withdrawn from trust account	500,561
Acquisition of Centennial Resource Production, LLC	(1,375,744)
Acquisition of oil and natural gas properties	(849,642)
Development of oil and natural gas properties	(24,107)
Purchases of other property and equipment	(801)
Development of assets held for sale	0
Proceeds from sales of oil and natural gas properties and other assets	0
Proceeds from sale of Atlantic Midstream, net of cash sold	0
Cash held in escrow	0
Net cash used by investing activities	(1,749,733)
Cash flows from financing activities:
Issuance of Class A common shares	1,540,556
Issuance of Preferred Series B shares	379,494
Payment of underwriting fees	(27,104)
Payment of deferred underwriting compensation	(17,500)
Proceeds from revolving credit facility	0
Repayment of revolving credit facility	0
Capital contributions	0
Financing obligation	(63)
Debt issuance costs	(1,115)
Repurchase of equity	0
Proceeds from term loan	0
Distribution in connection with common control acquisition	0
Contributions received from noncontrolling interest	0
Net cash provided by financing activities	1,874,268
Net increase (decrease) in cash and cash equivalents	133,945
Cash and cash equivalents, beginning of period	138
Cash and cash equivalents, end of period	134,083	$ 138
Supplemental cash flow information
Cash paid for interest	234
Supplemental noncash activity
Accrued capital expenditures included in accounts payable and accrued expenses	65,217
Financing obligation	0
Predecessor
Net (loss) income		(218,724)	$ (38,325)	$ 17,788
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion of asset retirement obligations		134	139	156
Depreciation, depletion and amortization		62,830	89,945	68,954
Equity based compensation expense		0	0	12,420
Incentive unit compensation		165,394	0	0
Noncash transaction costs		14,049	0	0
Abandonment expense and impairment of unproved properties		2,545	7,619	20,025
Write-off of deferred S-1 related expense		0	1,585	0
Deferred tax (benefit) expense		(406)	(572)	1,524
(Gain) loss on sale of oil and natural gas properties		(11)	(2,439)	2,096
Loss (gain) on derivative instruments		6,838	(20,756)	(41,943)
Net cash received for derivative settlements		16,623	35,493	4,611
Recovery of bad debt		0	0	(777)
Amortization of debt issuance costs		376	482	316
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		969	5,244	(6,322)
Increase in prepaid and other assets		(170)	(864)	(79)
Increase (decrease) in accounts payable and other liabilities		1,293	(8,669)	18,479
Net cash provided by operating activities		51,740	68,882	97,248
Cash flows from investing activities:
Proceeds withdrawn from trust account		0	0	0
Acquisition of Centennial Resource Production, LLC		0	0	0
Acquisition of oil and natural gas properties		(55,564)	(43,223)	(22,167)
Development of oil and natural gas properties		(45,605)	(156,006)	(275,683)
Purchases of other property and equipment		(265)	(2,097)	(453)
Development of assets held for sale		0	0	(14,240)
Proceeds from sales of oil and natural gas properties and other assets		0	2,691	72,382
Proceeds from sale of Atlantic Midstream, net of cash sold		0	0	71,781
Cash held in escrow		0	0	5,000
Net cash used by investing activities		(101,434)	(198,635)	(163,380)
Cash flows from financing activities:
Issuance of Class A common shares		0	0	0
Issuance of Preferred Series B shares		0	0	0
Payment of underwriting fees		0	0	0
Payment of deferred underwriting compensation		0	0	0
Proceeds from revolving credit facility		55,000	92,000	196,000
Repayment of revolving credit facility		(5,000)	(83,000)	(160,000)
Capital contributions		0	111,396	59,776
Financing obligation		(2,074)	(1,633)	0
Debt issuance costs		0	(259)	(1,637)
Repurchase of equity		0	0	(119,272)
Proceeds from term loan		0	0	65,000
Distribution in connection with common control acquisition		0	0	(3,051)
Contributions received from noncontrolling interest		0	0	150
Net cash provided by financing activities		47,926	118,504	36,966
Net increase (decrease) in cash and cash equivalents		(1,768)	(11,249)	(29,166)
Cash and cash equivalents, beginning of period	$ 0	1,768	13,017	42,183
Cash and cash equivalents, end of period		0	1,768	13,017
Supplemental cash flow information
Cash paid for interest		5,092	5,782	1,935
Supplemental noncash activity
Accrued capital expenditures included in accounts payable and accrued expenses		21,025	13,124	81,510
Financing obligation		$ 0	$ 3,770	$ 0

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	Note 1—Basis of Presentation and Summary of Significant Accounting Policies Description of Business Centennial Resource Development, Inc. (the “Company”) was originally incorporated in Delaware on November 4, 2015 as a special purpose acquisition company under the name Silver Run Acquisition Corporation for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving the Company and one or more businesses. On February 29, 2016, the Company consummated its initial public offering of Units each consisting of one share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, the Company consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”). In connection with the closing of the Business Combination, the Company changed its name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc." and continued the listing of its Class A Common Stock and Public Warrants on NASDAQ under the symbols "CDEV" and "CDEVW," respectively. Refer to Note 2—Business Combination for further discussion of the Business Combination. CRP was formed in August 2012 by an affiliate of NGP Energy Capital Management, a family of energy-focused private equity investment funds, in connection with the acquisition of all of the oil and natural gas properties and certain other assets of Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas company. The Company’s Class A Common Stock and Public Warrants trade on The NASDAQ Capital Market (“NASDAQ”) under the ticker symbols “CDEV” and “CDEVW,” respectively. The Units automatically separated into their component securities prior to or upon closing of the Business Combination and, as a result, no longer trade as a separate security. The consolidated financial statements include the accounts of the Company and CRP and its wholly-owned subsidiaries. Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated and combined financial statements. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2016 , through the filing date of this report. As a result of the Business Combination, the Company is the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. The Company’s financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016. The Merger was accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of the net assets acquired. Refer to Note 2—Business Combination for further discussion of the Business Combination. As a result of the application of the acquisition method of accounting as of the Business Combination, the financial statements for the Predecessor period and for the Successor period are presented on a different basis of accounting and are therefore, not comparable. Principles of Consolidation The consolidated financial statements included herein have been prepared in accordance with GAAP and the rules and regulations of Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP, and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. Use of Estimates The preparation of the Company’s consolidated and combined financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established. The more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables. Cash and Cash Equivalents The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank. Accounts Receivable Accounts receivable consists mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months and the Company has had minimal bad debts. Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company establishes an allowance for doubtful accounts equal to the estimable portions of accounts receivable for which failure to collect is probable. The Company had no allowance for doubtful accounts at December 31, 2016 (Successor) . The allowance for doubtful accounts at December 31, 2015 (Predecessor) was $0.1 million . Credit Risk and Other Concentrations The Company normally sell production to a relatively small number of customers, as is customary in its business. For the year ended December 31, 2016 , sales to Plains Marketing, LP (“Plains”), Shell Trading (US) Company, and Permian Transport and Trading accounted for 48% , 22% , and 11% , respectively, of the total revenue. For the years ended December 31, 2015 and December 31, 2014 , the Company only had one major customer, Plains, which accounted for 64% and 78% , respectively, of total revenue. The loss of any of the Company’s major purchasers could materially and adversely affect its revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that the loss of any major purchaser would not have a material adverse effect on its financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers. By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. As of December 31, 2016 , and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. The credit facility is secured by the Company’s proved oil and natural gas properties and therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $0.7 million at December 31, 2016 (Successor) . The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; and (ii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated. The Company places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the years ended December 31, 2016 (Successor) and December 31, 2015 (Predecessor) , the Company has not incurred losses related to these investments. Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells and development wells are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. As of December 31, 2016 (Successor) and December 31, 2015 (Predecessor) , no costs were capitalized in connection with exploratory wells in progress. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to income. Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or otherwise attributed to the property. There was no abandonment and impairment expense for the period from October 11, 2016, through December 31, 2016 (Successor) . For the period from January 1, 2016, through October 10, 2016 (Predecessor) , the Company recorded abandonment and impairment expense of $2.5 million for leases which have expired, or are expected to expire. For the year ended December 31, 2015 (Predecessor) , the Company recorded abandonment and impairment expense of $7.6 million for leases which have expired, or are expected to expire. For the year ended December 31, 2014 (Predecessor) , the Company recorded impairment expense of $20.0 million , of which $13.8 million was attributable to an impairment of unproved properties and $6.2 million was attributable to leases which had expired, or were expected to expire. The Company reviews it proved oil and natural gas properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. There were no impairments of proved oil and natural gas properties for the periods October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) and for the years ended December 31, 2015 (Predecessor) and December 31, 2014 (Predecessor) . Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, vehicles, and computer hardware and software is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets ranging from three to twenty years. Major renewals and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. Deferred Loan Costs Deferred loan costs related to the Company’s revolving credit facility are included in the line item Other noncurrent assets in the consolidated balance sheets and are stated at cost, net of amortization. These costs are amortized to interest expense on a straight line basis over the borrowing term. Derivative Financial Instruments In order to manage its exposure to oil and natural gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements relating to the price risk associated with a portion of its production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position. The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. The Company’s derivatives have not been designated as hedges for accounting purposes. For additional discussion on derivatives, please refer to Note 9—Derivative Instruments . Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and natural gas properties in the accompanying consolidated balance sheets. The Company depletes the amount added to proved oil and natural gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. For additional discussion, please refer to Note 11—Asset Retirement Obligations . Revenue Recognition The Company derives revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company follows the sales method of accounting for its oil and natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. The Company had no significant imbalances as of December 31, 2016 or 2015 . Income Taxes Income taxes and uncertain tax positions are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 740, Accounting for Income Taxes (“ASC 740”). Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth in ASC 740. A valuation allowance is established when necessary to reduce deferred tax assets to the amount expected to be realized. Equity Based Compensation (Successor) The Company recognizes compensation related to all stock-based awards, including stock options, in the financial statements based on their estimated grant-date fair value. The Company grants various types of stock-based awards including stock options and restricted stock. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock are valued using the market price of the Company’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 8—Equity Based Compensation for additional information regarding the Company’s equity based compensation (successor). Equity Based Compensation (Predecessor) Pursuant to the LLC Agreement of CRP (prior to the Business Combination), certain incentive units were available to be issued to the Company’s management and employees, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The incentive units were intended to be compensation for services rendered to CRP. Tier Incentive units are accounted for as liability awards under FASB ASC Topic 718, Compensation: Stock Compensation (“ASC 718”) , with compensation expense based on period-end fair value. Refer to Note 8—Equity Based Compensation for additional information regarding the CRP’s equity based compensation (Predecessor). Earnings (Loss) Per Share The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Basic earnings (loss) per share is calculated by dividing earnings (loss) available to common shareholders by the weighted average shares-basic during each period. The Company’s preferred series B shares have a non-forfeitable right to participate in distributions with common stockholders on a pro rata, as-converted basis and as such are considered participating securities. Shares of the Company’s unvested restricted stock are eligible to receive dividends; however, dividend rights will be forfeited if the award does not vest. Accordingly, these shares are not considered participating securities. Shares of the Company’s class C common stock and warrants do not share in the earnings or losses and are therefore not participating securities. The Company uses the "if-converted" method to determine the potential dilutive effect of exchanges of outstanding CRP Common Units and corresponding shares of its outstanding Class C common stock, and the treasury stock method to determine the potential dilutive effect of its outstanding restricted stock and stock options. The following table reflects the allocation of net income to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period: Successor October 11, 2016 (in thousands, except per share data) Net income (loss) $ (8,081 ) Less: Loss allocable to participating securities (46 ) Net loss available for common shareholders $ (8,035 ) Basic net loss per share $ (0.05 ) Diluted net loss per share $ (0.05 ) Basic weighted average share outstanding 165,684 Add: Dilutive effects of stock options and RSUs — Diluted weighted average shares outstanding 165,684 Options and restricted shares of 2.7 million and 0.3 million , respectively, were not included in the weighted average shares-dilutive calculation for the period from October 11, 2016, through December 31, 2016 because their effect would have been anti-dilutive. Segment Reporting The Company operates in only one industry segment which is the exploration and production of oil and natural gas. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States. Recently Issued Accounting Standards In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update should be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of the Company’s cash flows and will not have a material impact on its consolidated financial statements. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing . This update clarifies two principles of ASC Topic 606, Revenue from Contracts with Customers : identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net) , the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Company’s financial position, results of operations and liquidity. March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation . This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net) . Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of this update will have on its financial position, results of operations and liquidity. In February 2016, the FASB issued ASU 2016-02, Leases . This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on its balance sheet for current operating leases. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application permitted for annual reporting period beginning after December 31, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact of this standard on its consolidated financial statements. Subsequent Events On March 1, 2017, the Company delivered a notice of redemption of the Public Warrants, announcing its intention to redeem any unexercised and outstanding Public Warrants on March 31, 2017 for $0.01 per Public Warrant. As permitted under the warrant agreement that provides the terms of the Public Warrants, the notice of redemption requires all holders exercising their Public Warrants prior to March 31, 2017 to do so on a “cashless basis” and surrender their Public Warrants for a number of shares of Class A Common Stock equal to the product of the quotient equal to (i) the difference between $11.50 and $18.44 (the average last sale price of the Class A Common Stock for the ten trading days ending on February 24, 2017) divided by (ii) $18.44 , or approximately 0.376 , multiplied by the number of Public Warrants held by such holder, rounded down to the nearest whole share. Assuming all warrants are exercised by holders, Centennial will issue approximately 6.27 million shares of Class A Common Stock to the Public Warrant holders, resulting in a share count of approximately 253 million shares outstanding, which includes Class A Common Stock shares, the shares of Series B Preferred Stock held by Riverstone (assuming conversion to Class A Common Stock on a 250-to-one basis), and the shares of Class C Common Stock held by the Centennial Contributors. The Private Placement Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees. Refer to Note 7—Shareholders' and Owners' Equity for additional information regarding the Company’s warrants.

Business Combination (Notes)

Business Combination (Notes)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Business Combination	Note 2—Business Combination On October 11, 2016 (the "Closing Date"), the Company consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), pursuant to (i) that certain Contribution Agreement, dated as of July 6, 2016 (as amended by Amendment No. 1 thereto, dated as of July 29, 2016, the "Contribution Agreement"), among Centennial Resource Development, LLC, a Delaware limited liability company ("CRD"), NGP Centennial Follow-On LLC, a Delaware limited liability company ("NGP Follow-On"), Celero Energy Company, LP, a Delaware limited partnership (together with CRD and NGP Follow-On, the "Centennial Contributors"), CRP and New Centennial, LLC, a Delaware limited liability company ("NewCo"), (ii) that certain Assignment Agreement, dated as of October 7, 2016, between NewCo and the Company and (iii) that certain Joinder Agreement, dated as of October 7, 2016, by the Company (such acquisition, together with the other transactions contemplated by the Contribution Agreement, the "Business Combination"). At the closing of the Business Combination (the "Closing"), Silver Run contributed to CRP approximately $1.49 billion in cash and CRP then distributed to the Centennial Contributors cash in the amount of approximately $1.19 billion in partial redemption of the Centennial Contributors' membership interests in CRP. At the Closing, Silver Run and the Centennial Contributors effected a recapitalization of CRP pursuant to which (1) all of the remaining outstanding membership interests in CRP of the Centennial Contributors were converted into 20,000,000 units representing common membership interests in CRP (the "CRP Common Units") and (2) the Company was admitted as a member of CRP and issued 163,505,000 CRP Common Units, representing an approximate 89% interest in CRP. The Business Combination has been accounted using the acquisition method. The acquisition method of accounting is based on FASB ASC 805, Business Combination ("ASC 805"), and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements ("ASC 820"). ASC 805 requires, among other things, that most assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by Silver Run, who was determined to be the accounting acquirer. The purchase consideration for the Business Combination was as follows: (in thousands) October 11, 2016 Preliminary purchase consideration: Cash $ 1,186,744 Repayment of CRP long-term debt(1) 189,000 Total purchase price consideration 1,375,744 Fair value of non-controlling interest(2) 184,779 Total purchase price consideration and fair value of non-controlling interest $ 1,560,523 (1) Represents the additional contribution made by Silver Run to CRP in exchange for units representing common membership interest in CRP ("CRP Common Units"), to repay CRP's outstanding indebtedness at the Closing Date. (2) Represents the fair value of the non-controlling interest (NCI) attributable to the Centennial Contributors. NCI is the portion of equity (net assets) in a subsidiary not attributable, directly or indirectly to Silver Run. In a business combination the NCI is recognized at its acquisition date fair value in accordance with ASC 805. The fair value of the NCI represents a 11% membership interest in CRP. The following table summarizes the allocation of the purchase consideration to the assets acquired and liabilities assumed: (in thousands) October 11, 2016 Fair value of assets acquired: Other current assets $ 13,341 Derivative instruments 1,052 Oil and gas properties(1): Proved properties 444,551 Unproved properties 1,138,423 Other property, plant and equipment 1,764 Goodwill — Total fair value of assets acquired 1,599,131 Fair value of liabilities assumed: Accounts payable and accrued expenses 30,156 Other current liabilities 63 Derivative instruments(2) 3,400 Asset retirement obligation 4,989 Fair value of net assets acquired $ 1,560,523 (1) The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. The reduction in the carrying cost of the proved properties was impacted by all of these factors, but most notably, the assumptions with respect to future commodity prices as of the valuation date. (2) The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s own nonperformance risk, each based on the current published credit default swap rates. Unaudited Pro Forma Operating Results The following unaudited pro forma combined financial information has been prepared as if the Business Combination and other related transactions had taken place on January 1, 2015. The unaudited pro forma consolidated financial information has been prepared using the acquisition method of accounting in accordance with GAAP. The information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including depletion of CRP’s fair-valued proved oil and gas properties, and the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2016, were adjusted to exclude $18.7 million of transaction-related costs and $165.4 million of incentive unit compensation incurred by CRP. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Business Combination taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results. (Unaudited Pro Forma) Year Ended December 31, (in thousands) 2016 2015 Total revenues $ 98,833 $ 90,460 Total operating expenses 86,490 123,702 Net income (loss) attributable to common shareholders of Centennial Resource Development, Inc. 1,666 (6,397 ) Basic and diluted net loss per share 0.01 (0.04 )

Property Acquisitions and Dispo

Property Acquisitions and Dispositions (Notes)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Property Acquisitions and Dispositions	Note 3—Property Acquisitions and Dispositions 2016 Acquisitions In December 2016, the Company acquired undeveloped acreage and oil and gas producing properties located in Reeves County, Texas from Silverback Exploration, LLC. for an aggregate price of approximately $855.0 million , subject to customary purchase price adjustments. Approximately $116.7 million was recorded as proved oil and natural gas properties with the remaining recorded to unproved oil and natural gas properties. Approximately $32.3 million of the purchase price is included in accounts payable on the consolidated balance sheet as of December 31, 2016. This remaining amount will be paid when all the title issues related to the acquisition have been satisfied. The assets include 31 operated producing horizontal wells and approximately 35,500 net acres that directly offset the Company’s existing acreage in Reeves County, Texas. Of the net acres acquired, 1,250 net acres are subject to consents to assign, which are expected to be assigned in the first quarter of 2017. The Company operates approximately 90% of, and has an approximate 90% working interest in, this acreage. The Wolfcamp A and Wolfcamp C are producing horizons on this acreage and the Company believes that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations. In June 2016, the Company acquired undeveloped acreage and oil and gas producing properties located in Reeves County, Texas. Total cash consideration paid by the Company was $33.0 million , including usual and customary post-closing adjustments. Approximately $15.4 million was recorded as proved oil and natural gas properties. The assets include four operated producing horizontal wells and approximately 1,580 net acres that directly offset the Company’s existing acreage in Reeves County, Texas. Predecessor (in thousands) June 3, 2016 Cash consideration $ 32,979 Fair value of assets and liabilities acquired: Proved oil and natural gas properties 15,374 Unproved oil and natural gas properties 18,071 Total fair value of oil and natural gas properties acquired 33,445 Revenue Suspense (400 ) Asset retirement obligation (66 ) Total fair value of net assets acquired $ 32,979 In May 2016, the Company acquired unproved acreage in close proximity to its operating area in Reeves County, Texas and wellbore only rights in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB, LLC. The assets included approximately 875 net acres that directly offset the Company’s existing acreage. 2015 Acquisitions On September 1, 2015, the Company acquired additional interests in proved and unproved oil and natural gas properties in the Delaware Basin. Total cash consideration paid by the Company was $16.0 million , net of closing adjustments. On September 3, 2015, the Company acquired a non-operated interest in 1,804 net acres in the Delaware Basin from an unrelated third party. Total cash consideration paid by the Company was $6.4 million , net of closing adjustments. The Company allocated the final purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. Predecessor Acquisition #1 Acquisition #2 (in thousands) September 1, 2015 September 3, 2015 Cash consideration $ 16,006 $ 6,369 Fair value of assets and liabilities acquired: Proved oil and natural gas properties 7,731 6,491 Unproved oil and natural gas properties 8,312 — Total fair value of oil and natural gas properties acquired 16,043 6,491 Asset retirement obligation (37 ) (122 ) Total fair value of net assets acquired $ 16,006 $ 6,369 2014 Acquisitions In June 2014, the Company acquired 2,400 net acres in the Delaware Basin from an unrelated third party, for approximately $11.0 million , net of customary closing adjustments. 2014 Dispositions In December 2014, the Company sold its interest in approximately 1,845 net acres in Ward County, Texas, including 18 vertical wells, to an NGP-controlled entity for proceeds of $12.5 million , which resulted in a gain of $1.5 million and was recorded as an equity contribution due to the entities being under common control. In May 2014, the Company sold its Caprock field to an unrelated third party for $59.3 million , net of customary closing adjustments. A net loss of $2.2 million was recognized on the sale during the second quarter of 2014. In February 2014, the Company sold its 98.5% interest in Atlantic Midstream to PennTex Permian, an NGP-controlled entity for net proceeds of $71.8 million , which resulted in a gain of $20.0 million and was recorded as an equity contribution due to the entities being under common control.

Accounts Receivable, Accounts P

Accounts Receivable, Accounts Payable and Accrued Expenses	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Accounts Receivable, Accounts Payable and Accrued Expenses	Note 4—Accounts Receivable, Accounts Payable and Accrued Expenses Accounts receivable are comprised of the following: Successor Predecessor (in thousands) December 31, 2016 December 31, 2015 Oil and natural gas $ 11,596 $ 5,789 Joint interest billings 2,942 1,514 Hedge settlements 194 3,956 Other 2 1,844 Allowance for doubtful accounts — (91) Accounts receivable, net $ 14,734 $ 13,012 Accounts payable and accrued expenses are comprised of the following: Successor Predecessor (in thousands) December 31, 2016 December 31, 2015 Accounts payable $ 11,210 $ 1,827 Accrued capital expenditures 24,038 11,700 Revenues payable 3,815 3,439 Payable to Silverback 32,293 — Accrued underwriting fees 7,719 — Other 7,025 3,019 Accounts payable and accrued expenses $ 86,100 $ 19,985

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Note 5—Long-Term Debt Credit Agreement (Successor) In connection with the consummation of the Business Combination, all indebtedness under CRP’s term loan and revolving credit facility was repaid in full. On October 11, 2016, CRP entered into a second amendment to the amended and restated credit agreement (the “second amendment”), which amends the amended and restated credit agreement, dated as of October 15, 2014, among CRP, each of the lenders from time to time party thereto and JPMorgan Chase Bank, N.A. as administrative agent (the “credit agreement”). CRP entered into the second amendment to, among other things, (i) permit the Business Combination, (ii) reflect the repayment in full of all term loans thereunder, (iii) increase the borrowing base from $140.0 million to $200.0 million , (iv) increase the interest rate to LIBOR plus 225 to 325 basis points, and (v) require CRP to have sufficient liquidity and satisfy a maximum leverage ratio in order to make dividends. On December 28, 2016, in connection with the closing of the Silverback Acquisition, CRP entered into a third amendment to the amended and restated credit agreement (the “third amendment”), which further amends the credit agreement. CRP entered into this amendment to, among other things, increase the borrowing base thereunder from $200.0 million to $250.0 million . The amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that will be redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumes of CRP's proved oil and natural gas reserves and estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. The next regular redetermination date is scheduled for the spring of 2017. Borrowings under its revolving credit facility may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements) plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank's prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one -month interest period plus 100 basis points, plus an applicable margin ranging from 125 to 225 basis points, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee on unused amounts of its revolving credit facility of 50 basis points. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. CRP's credit agreement contains restrictive covenants that limit its ability to, among other things: (1) incur additional indebtedness; (2) make investments and loans; (3) enter into mergers; (4) make or declare dividends; (5) enter into commodity hedges exceeding a specified percentage of its expected production; (6) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (7) incur liens; (8) sell assets; and (9) engage in transactions with affiliates. CRP's credit agreement also requires it to maintain compliance with the following financial ratios: (1) a current ratio, which is the ratio of CRP's consolidated current assets (including unused commitments under CRP's revolving credit facility and excluding non-cash assets under FASB ASC Topic 815, Derivatives and Hedging (“ASC 815”) and certain restricted cash) to consolidated current liabilities (excluding the current portion of long-term debt under its credit agreement and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0 ; and (2) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP's credit agreement) to consolidated EBITDAX (as defined in CRP's credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0 . At December 31, 2016 , there were no borrowings under the revolving credit facility. Outstanding letters of credit were $0.4 million , leaving $249.6 million in borrowing capacity under the revolving credit facility. At December 31, 2016 , the Company was in compliance with all required covenants. Term Loan and Revolving Credit Facility (Predecessor) On October 15, 2014, CRP entered into an amended and restated credit agreement (as amended, the "credit agreement") with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders, that includes both a term loan commitment of $65.0 million (the "term loan"), which was fully funded as of October 10, 2016 , and a revolving credit facility (the "revolving credit facility") with commitments of $500.0 million (subject to the borrowing base), with a sublimit for letters of credit of $15.0 million . Prior to the Business Combination, the borrowing base was $140.0 million . On October 10, 2016 , CRP had $124.0 million outstanding under its revolving credit facility and $0.4 million of letters of credit outstanding, leaving $15.6 million in borrowing capacity under the revolving credit facility. The credit agreement also has customary covenants with which CRP was in compliance on October 10, 2016 , prior to the Business Combination. The term loan, net of unamortized deferred financing costs on the accompanying consolidated balance sheets as of December 31, 2015 , consisted of the following: Predecessor (in thousands) December 31, 2015 Term loan $ 65,000 Unamortized deferred financing costs (351) Term loan, net of unamortized deferred financing costs $ 64,649

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 6—Income Taxes As a result of the Business Combination, the Company became the sole managing member of CRP, and as a result, began consolidating the financial results of CRP. CRP is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, CRP is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by CRP is passed through to and included in the taxable income or loss of its members, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes with respect to its allocable share of any taxable income or loss of CRP, as well as any stand-alone income or loss generated by the Company. Income tax benefit (expense) are included in the consolidated statements of operations are detailed below: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Current taxes Federal $ — $ — $ — $ — State — — — — — — — — Deferred taxes Federal — — — — State — 406 572 (1,524 ) — 406 572 (1,524 ) Income tax benefit (expense) $ — $ 406 $ 572 $ (1,524 ) A reconciliation of the statutory federal income tax expense to the income tax expense from continuing operations provided at December 31, 2016, is as follows: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Income tax (benefit) expense at the federal statutory rate $ (3,145 ) $ — $ — $ — State income taxes - net of federal income tax benefits — 406 572 (1,524 ) Excess depletion — — — — Noncontrolling interest in partnership 273 — — — Nondeductible expenses 4 — — — Change in valuation allowance 2,868 — — — Income tax benefit (expense) $ — $ 406 $ 572 $ (1,524 ) The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below: Successor Predecessor (in thousands) December 31, 2016 December 31, 2015 Deferred tax assets: Net operating loss carryforwards $ 2,590 $ — Capitalized intangible drilling cost 10,314 — Equity-based compensation 467 — Other assets 291 — Total deferred tax assets 13,662 — Deferred tax liabilities: Investment in Centennial Resource Production, LLC (8,514 ) — Other liabilities — (2,361 ) Total deferred tax liabilities (8,514 ) (2,361 ) Valuation allowance (5,148 ) — Net deferred tax asset (liabilities) $ — $ (2,361 ) For the period from October 11, 2016, through December 31, 2016 (Successor) , equity was debited $5.6 million in connection with the issuance of shares to a noncontrolling interest owner. No tax benefit was recorded in equity as a $2.0 million valuation allowance fully offset the attendant tax benefit. As of December 31, 2016 , the Company had approximately $7.3 million of federal net operating loss carryovers that commence expiry in 2035. The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. It is currently estimated that the Company’s net deferred tax assets will not be utilized. Accordingly, a valuation allowance against the net deferred tax assets has been recorded at December 31, 2016 . The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon the examination by the Internal Revenue Service or other governmental agency. As of December 31, 2016 , the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Interest and penalties related to uncertain tax positions are reported in income tax expense. The Company is subject to the following material taxing jurisdictions: U.S., Colorado and Texas. As of December 31, 2016 , the Company has no current tax years under audit. The Company remains subject to examination for federal income taxes and state income taxes for tax years 2015 and 2016.

Shareholders' and Owners Equity

Shareholders' and Owners Equity (Notes)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Shareholders' and Owners' Equity	Note 7—Shareholders' and Owners' Equity Shareholders’ Equity (Successor) At December 31, 2016 , the Company had authorized 621,000,000 shares of capital stock, consisting of (a) 620,000,000 shares of common stock, including (i) 600,000,000 shares of Class A Common Stock, (ii) 20,000,000 shares of Class C Common Stock and (b) 1,000,000 shares of preferred stock, including one share of Series A Preferred Stock and 104,400 shares of Series B Preferred Stock. On October 11, 2016, in connection with Business combination the Company issued and sold in private placements (i) 81,005,000 shares of Class A Common Stock to Riverstone Centennial Holdings, L.P. and (ii) the issuance and sale of 20,000,000 shares of Class A Common Stock to certain other accredited investors in a private placement, resulting in net cash proceeds of approximately $1.0 billion . The outstanding shares of Class B Common Stock, par value $0.0001 per share, converted into shares of Class A Common Stock on a one -for- one basis in connection with the Business Combination. Additionally, the Company issued 20,000,000 shares of Class C Common Stock to the Centennial Contributors and one share of Series A Preferred Stock to CRD in connection with the Business Combination. Holders of Class C Common Stock, generally have the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of the Company's Class A Common Stock or, at CRP's option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such CRP Common Units in lieu of such a redemption by CRP. Upon the future redemption or exchange of CRP Common Units held by a Centennial Contributor, a corresponding number of shares of Class C Common Stock will be canceled. On December 28, 2016, in connection with the Silverback Acquisition, the Company issued and sold in private placements (i) 3,473,590 shares of Class A Common Stock and 104,400 shares of Series B Preferred Stock to Riverstone VI Centennial QB Holdings, L.P., Riverstone Non-ECI USRPI AIV, L.P. and REL US Centennial Holdings, LLC, which are affiliates of Riverstone Investment Group LLC and (ii) 33,012,380 shares of the Company’s Class A Common Stock to certain other investors, resulting in net cash proceeds of approximately $889.6 million . The Company used the proceeds from the private placements to fund the cash consideration for the Silverback Acquisition and expect to use any remaining proceeds for general corporate purposes. The shares of Series B Preferred Stock are automatically convertible into shares of the Company’s Class A Common Stock on a 250 -to- one basis (subject to certain adjustments for stock splits, stock dividends, reorganization, recapitalizations and the like) at such time as the Company receives stockholder approval for the issuance of such shares of Class A Common Stock in compliance with NASDAQ listing rules. Class A Common Stock The Company had 201,091,646 shares of Class A Common Stock outstanding as of December 31, 2016, consisting of (i) 50,000,000 shares of Class A Common Stock issued as part of Units in connection with the IPO, (ii) 12,500,000 shares of Class A Common Stock issued upon conversion of the Company’s Class B Common Stock, par value $0.0001 per share, in connection with the Business Combination (iii) 101,005,000 shares of Class A Common Stock issued in private placements in connection with the Business Combination, (iv) 844,079 shares of Class A Common Stock issued upon the redemption of CRP Common Units and cancellation of shares of Class C Common Stock, (v) 36,485,970 shares of Class A Common Stock issued in private placements in connection with the Silverback Acquisition and (vi) 256,597 restricted shares of Class A Common Stock issued to the Company’s directors and executive officers. Additional shares of Class A Common Stock may be issued by the Company upon the exchange of CRP Common Units and cancellation of shares of Class C Common Stock pursuant to the A&R LLC Agreement (as defined below), the conversion of the Series B Preferred Stock and the exercise of the Company’s outstanding Warrants. Holders of the Company's Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by the Company's stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock will vote together as a single class on all matters submitted to a vote of the Company's stockholders, except as required by law. Unless specified in the Charter (including any certificate of designation of preferred stock) or Bylaws, or as required by applicable provisions of the Delaware General Corporation Law or applicable stock exchange rules, the affirmative vote of a majority of the Company's shares of common stock that are voted is required to approve any such matter voted on by the Company's stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors (subject to the right of the holder of the Company’s Series A Preferred Stock to nominate and elect one director). Subject to the rights of the holders of any outstanding series of preferred stock, the Company's stockholders are entitled to receive ratable dividends when, as and if declared by the board of directors out of funds legally available therefor. In the event of a liquidation, dissolution or winding up of the Company, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Class A Common Stock. The Company's stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock. Class C Common Stock The Company had 19,155,921 shares of Class C Common Stock outstanding as of December 31, 2016, which represent the portion of the 20,000,000 shares of Class C Common Stock issued to the Centennial Contributors in connection with the Business Combination that had not been redeemed or exchanged as of such date. Holders of Class C Common Stock, together with holders of Class A Common Stock voting as a single class, will have the right to vote on all matters properly submitted to a vote of the stockholders. In addition, the holders of Class C Common Stock, voting as a separate class, will be entitled to approve any amendment, alteration or repeal of any provision of the Company’s Charter that would alter or change the powers, preferences or relative, participating, optional or other or special rights of the Class C Common Stock. Holders of Class C Common Stock will not be entitled to any dividends from the Company and will not be entitled to receive any of its assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of its affairs. Shares of Class C Common Stock may be issued only to the Centennial Contributors, their respective successors and assigns, as well as any permitted transferees of the Centennial Contributors. A holder of Class C Common Stock may transfer shares of Class C Common Stock to any transferee (other than the Company) only if such holder also simultaneously transfers an equal number of such holder's CRP Common Units to such transferee in compliance with the A&R LLC Agreement (as defined below). Holders of Class C Common Stock generally have the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of the Company's Class A Common Stock or, at CRP's option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such CRP Common Units in lieu of such a redemption by CRP. Upon the future redemption or exchange of CRP Common Units held by a Centennial Contributor, a corresponding number of shares of Class C Common Stock will be canceled. Preferred Stock As of December 31, 2016, the Company had outstanding one share of Series A Preferred Stock, issued to CRD in connection with the Business Combination, and 104,400 shares of Series B Preferred Stock, issued and sold to certain affiliates of Riverstone in connection with the Silverback Acquisition. CRD, as the holder of the Series A Preferred Stock, will not be entitled to any dividends from the Company, but will be entitled to preferred distributions in liquidation in the amount of $0.0001 per share of Series A Preferred Stock and will have a limited voting right as described below. The Series A Preferred Stock will be redeemable by the Company (a) at such time as CRD and its affiliates cease to own, in the aggregate, at least 5,000,000 CRP Common Units and/or shares of Class A Common Stock (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions), (b) at any time at CRD's option or (c) upon a breach by CRD of the transfer restrictions relating to the Series A Preferred Stock. In addition, for so long as the Series A Preferred Stock remains outstanding, CRD will be entitled to nominate one director for election to the Company’s board of directors in connection with any vote of the Company’s stockholders for the election of directors, and the vote of CRD will be the only vote required to elect such nominee to the Company’s board of directors. Holders of Series B Preferred Stock generally will not have any voting rights, except as required by law. Notwithstanding the foregoing, the affirmative vote of holders of a majority of the Series B Preferred Stock then outstanding, voting as a separate class, is required to (a) approve any amendment, alteration or repeal of any provision of the Certificate of Designation relating to the Series B Preferred Stock or the Charter that adversely affects the rights, preferences, privileges or voting powers of the Series B Preferred Stock or (b) authorize the issuance of any senior securities or parity securities. With respect to any matter on which the holders of Series B Preferred Stock are entitled to vote, each share of Series B Preferred Stock will be entitled to one vote on such matter. Beginning on December 28, 2019, the third anniversary of the closing date of the Silverback Acquisition, the Company will have the right, but not the obligation, to redeem all (but not less than all) of each holder's shares of Series B Preferred Stock for a redemption price per share, determined on an as-converted basis, equal to the average of the last reported sale price for a share of Class A Common Stock on NASDAQ for each of the last ten consecutive trading days prior to the redemption date or, if such shares are no longer traded, at the fair market value of the Class A Common Stock, as determined in good faith by the Company’s board of directors. In the event of a voluntary or involuntary liquidation, dissolution or winding up of the Company, holders of the Series B Preferred Stock will first be entitled to receive the liquidation preference per share of $0.0001 before any distribution of assets is made to holders of any junior securities. The shares of Series B Preferred Stock are automatically convertible into shares of the Company’s Class A Common Stock on a 250 -to- one basis (subject to certain adjustments) at such time as the Company receives stockholder approval for the issuance of such shares of Class A Common Stock in compliance with NASDAQ listing rules. Warrants As of December 31, 2016, the Company had 24,666,643 warrants outstanding, consisting of 16,666,643 public warrants originally sold as part of the Units in the IPO and 8,000,000 Private Placement Warrants sold to the Company’s Sponsor in a private placement. Each whole warrant entitles the holder to purchase one whole share of Class A Common Stock for $11.50 per share. The warrants became exercisable on March 1, 2017 and will expire five years after the completion of the Business Combination or earlier upon redemption or liquidation. On March 1, 2017, the Company delivered a notice of redemption of the Public Warrants, announcing its intention to redeem any unexercised and outstanding Public Warrants on March 31, 2017 for $0.01 per Public Warrant. As permitted under the warrant agreement that provides the terms of the Public Warrants, the notice of redemption requires all holders exercising their Public Warrants prior to March 31, 2017 to do so on a “cashless basis” and surrender their Public Warrants for a number of shares of Class A Common Stock equal to the product of the quotient equal to (i) the difference between $11.50 and $18.44 (the average last sale price of the Class A Common Stock for the ten trading days ending on February 24, 2017) divided by (ii) $18.44 , or approximately 0.376 , multiplied by the number of Public Warrants held by such holder, rounded down to the nearest whole share. Assuming all warrants are exercised by holders, Centennial will issue approximately 6.27 million shares of Class A Common Stock to the Public Warrant holders, resulting in a share count of approximately 253 million shares outstanding, which includes Class A Common Stock shares, the shares of Series B Preferred Stock held by Riverstone (assuming conversion to Class A Common Stock on a 250 -to- one basis), and the shares of Class C Common Stock held by the Centennial Contributors. The Private Placement Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees. Noncontrolling Interest As a result of the exchange of CRP Common Units (and corresponding shares of Class C Common Stock) for Class A Common Stock (discussed in Note 12—Transactions with Related Parties ) on October 11, 2016, the Company’s ownership in CRP increased from 89.1% to 89.6% and the ownership of the other holders of CRP Common Units in CRP decreased from 10.9% to 10.4% . Because the increase in the Company’s ownership interest in CRP did not result in a change of control, the transaction was accounted for as an equity transaction under ASC Topic 810, Consolidations , which requires that any differences between the amount by which the carrying value of the Company’s basis in CRP and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. As a result of the December 28, 2016 private placements and the issuance of shares of Class A Common Stock and Series B Preferred Stock to the investors therein (discussed in Note 12—Transactions with Related Parties ), the net proceeds of which were contributed by the Company to CRP, the Company’s ownership of CRP increased from 89.6% to 92.2% and the other holders of CRP Common Units decreased from 10.4% to 7.8% . The Company has consolidated the financial position and results of operations of CRP and reflected that portion retained by the other holders of CRP Common Units as a noncontrolling interest. The following table summarizes the noncontrolling interest income (loss): Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 2014 Net loss attributable to noncontrolling interest $ (904 ) $ — $ — $ (2 ) Owners’ Equity (Predecessor) At October 10, 2016 (prior to the Business Combination), members included Centennial HoldCo, Celero and Follow-On, owning an approximate 61.2% , 21.2% and 17.6% membership interest in Centennial OpCo, respectively. CRP has two classes of membership interests outstanding: Class A, which consist of membership interests held by CRD and Follow-On; and Class B, which consist of membership interests held by Celero. On October 10, 2016 CRP recorded a deemed contribution attributable to the consummation of the Business Combination, which resulted in a Fundamental Change with respect to the incentive units and CRP recorded $165.4 million of compensation expense. Refer to Note 7—Shareholders' and Owners' Equity . Additionally, CRP recorded a deemed contribution of $14.0 million attributable to certain transaction costs related to the Business Combination paid by the Centennial Contributors. Refer to Note 2—Business Combination . As of December 31, 2015, CRD had contributed $289.4 million and had a remaining capital commitment of $32.5 million , Follow-On had contributed $84.2 million and had a remaining capital commitment of $100.3 million , and Celero had contributed $125.4 million and has no remaining capital commitment. In 2015 Follow-On contributed $84.2 million to Centennial OpCo in exchange for membership interests in Centennial CRP. In addition, CRD contributed approximately $27.2 million to CRP in exchange for additional membership interests in CRP.

Equity Based Compensation

Equity Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Based Compensation	Note 8—Equity Based Compensation Equity based compensation (Successor) The Company has recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Successor October 11, 2016 (in thousands) Restricted stock awards $ 405 Stock option awards 928 Total equity based compensation expense $ 1,333 Equity Incentive Plan On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”). An aggregate of 16,500,000 shares of Class A common stock will be available for issuance under the LTIP. The LTIP provides for grant of stock options, including incentive stock options ("ISOs") and nonqualified stock options ("NSOs"), stock appreciation rights ("SARs"), restricted stock, dividend equivalents, restricted stock units ("RSUs") and other stock or cash based awards. Restricted Stock The following table provides information about restricted stock awards granted in 2016 : Successor Awards Weighted Average Grant-Date Fair Value Service-based stock awards: Outstanding as of October 11, 2016 — $ — Vested — $ — Granted 256,597 $ 20.03 Canceled — $ — Outstanding as of December 31, 2016 256,597 $ 20.03 Compensation cost for the service-based vesting restricted shares is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. Unrecognized compensation cost related to unvested restricted shares at December 31, 2016 was $4.7 million . The Company expects to recognize that cost over a weighted average period of 2.6 years. Stock Options Options that have been granted under the LTIP expire ten years from the grant date and have service-based vesting schedules of three years. The exercise price for an option under the LTIP is the closing price of the Company’s common stock as reported by NASDAQ on the date of grant. Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates. The following summarizes the options granted and related information, and the assumptions used to determine the fair value of those options. Successor October 11, 2016 Options granted 2,760,500 Weighted average grant-date fair value $ 5.93 Weighted average exercise price $ 14.67 Total fair value (in thousands) $ 16,375 Expected term 6 Expected stock volatility 40.0 % Dividend yield — % Risk-free interest rate 1.5 % Information about outstanding stock options is summarized in the table below: Options Weighted Average Exercise Price Weighted Average Remaining Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding as of October 11, 2016 — $ — — — Exercised — $ — — — Granted 2,760,500 $ 14.67 5.8 $ 13,934 Forfeited (25,000 ) $ 14.52 5.8 $ 130 Outstanding as of December 31, 2016 2,735,500 $ 14.67 5.8 $ 13,804 Exercisable as of December 31, 2016 — $ — — $ — The following summary reflects the status of non-vested stock options as of December 31, 2016 and changes since the Business Combination on October 11, 2016 : Options Weighted Average Grant-Date Fair Value Weighted Average Exercise Price Non-vested as of October 11, 2016 — $ — $ — Vested — $ — $ — Granted 2,760,500 $ 5.93 $ 14.67 Forfeited (25,000 ) $ 5.86 $ 14.52 Non-vested as of December 31, 2016 2,735,500 $ 5.93 $ 14.67 As of December 31, 2016 , there was $15.3 million of unrecognized compensation cost related to non-vested stock options. The Company expects to recognize that cost on a pro rata basis over a weighted average period of 2.8 years. Equity based compensation (Predecessor) Incentive Units Certain employees of Centennial Resource Management, LLC, a wholly owned subsidiary of CRD at the time of grant, received an award of CRD and NGP Follow-On incentive units, or profits interests. All of the incentive units are non-voting and subject to certain vesting and performance conditions. The terms of the incentive units are as follows: Tier I and Tier II incentive units vest ratably over five years, but are subject to forfeiture if payout is not achieved. In addition, all unvested Tier I and Tier II incentive units vest immediately upon Tier I and Tier II payout, respectively. Tier III, IV and V incentive units vest only upon the achievement of certain payout thresholds for each such tier and each tier of incentive units is subject to forfeiture if the applicable required payouts are not achieved. In addition, vested and unvested incentive units are forfeited if an incentive unit holder's employment is terminated for any reason or if the incentive unit holder voluntarily terminates their employment. Payouts for each Tier I through Tier V are based upon achievement of specified rates of return on CRD and NGP Follow-Ons invested capital. The incentive units are issued to employees in return for services provided and cash payout is based, in part, on the value of Centennial equity; therefore, the incentive units are accounted for as liability awards under ASC 718, with compensation expense based on period-end fair value. The achievement of payout conditions is a performance condition that requires CRP to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. The consummation of the Business Combination resulted in a Fundamental Change with respect to the incentive units and CRP recorded $165.4 million of compensation expense. No incentive compensation expense was recorded at December 31, 2015 or 2014, because it was not probable that the performance criterion would be met.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Derivative Instruments	Note 9—Derivative Instruments The Company periodically uses derivative instruments to mitigate its exposure to a decline in commodity prices and the corresponding negative impact on cash flow available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and natural gas futures markets and the Company’s view of underlying supply and demand trends, it may increase or decrease its hedging positions. The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of December 31, 2016 : 2017 2018 Crude Oil Swaps: Notional volume (Bbl) 675,250 36,500 Weighted average fixed price ($/Bbl) $ 50.41 $ 55.95 Crude Oil Basis Swaps: Notional volume (Bbl) 127,750 — Weighted average fixed price ($/Bbl) $ (0.20 ) $ — Natural Gas Swaps: Notional volume (MMBtu) 1,460,000 — Weighted average fixed price ($/MMBtu) $ 2.94 $ — In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the NYMEX index price and a local index price. The oil basis derivative contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period. When the actual differential exceeds the fixed price provided by the basis swap contract, the Company receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Company pays the difference to the counterparty. The Company’s commodity derivatives are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. The fair value of the commodity contracts was a net liability of $5.0 million and a net asset of $21.1 million as of December 31, 2016 and December 31, 2015 , respectively. The following tables below summarize the gross fair value of derivative assets and liabilities and the effect of netting on the consolidated balance sheets (in thousands): Successor December 31, 2016 Balance Sheet Classification Gross Amounts Netting Adjustments Net Amounts Presented on the Consolidated Balance Sheets Assets Derivative instruments Current assets $ 739 $ (308 ) $ 431 Derivative instruments Noncurrent assets — — — Total assets $ 739 $ (308 ) $ 431 Liabilities Derivative instruments Current liabilities $ 5,669 $ (308 ) $ 5,361 Derivative instruments Noncurrent Liabilities 20 — 20 Total liabilities $ 5,689 $ (308 ) $ 5,381 Predecessor December 31, 2015 Balance Sheet Classification Gross Amounts Netting Adjustments Net Amounts Presented on the Consolidated Balance Sheets Assets Derivative instruments Current assets $ 19,469 $ (426 ) 19,043 Derivative instruments Noncurrent assets 2,071 (1 ) 2,070 Total assets $ 21,540 $ (427 ) $ 21,113 The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s consolidated and combined statements of operations. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings. The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 2014 (Loss) gain on derivative instruments $ (1,548 ) $ (6,838 ) $ 20,756 $ 41,943 The Company is exposed to financial risks associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which have a high credit rating and is a member of its bank credit facility. The Company’s member banks do not require it to post collateral for its hedge liability positions. Because some of the member banks have discontinued hedging activities, in the future the Company may hedge with counterparties outside its bank group to obtain competitive terms and to spread counterparty risk.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Fair Value Measurements	Note 10—Fair Value Measurements Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2016 and December 31, 2015 (in thousands): Successor December 31, 2016 Level 1 Level 2 Level 3 Commodity derivative liability, net(1) $ — $ 4,950 $ — Predecessor December 31, 2015 Level 1 Level 2 Level 3 Commodity derivative asset, net(1) $ — $ 21,113 $ — Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between Level 1, Level 2 or Level 3 during any period presented. Derivatives The Company uses Level 2 inputs to measure the fair value of oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. Nonrecurring Fair Value Measurements The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Refer to Note 2—Business Combination and Note 3—Property Acquisitions and Dispositions for additional information on the fair value of assets acquired during 2016 . Other Financial Instruments The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under the credit agreement approximate fair value because the variable interest rates are reflective of current market conditions.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 11—Asset Retirement Obligations The following table summarizes the changes in the Company’s asset retirement obligations for the periods presented: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 (in thousands) Asset retirement obligations, beginning of period $ 4,989 $ 2,288 $ 1,824 Liabilities incurred 187 174 133 Liabilities acquired 2,002 66 178 Liabilities settled (1 ) (42 ) — Accretion expense 49 134 139 Revision of estimated liabilities — 32 14 Asset retirement obligations, end of period $ 7,226 $ 2,652 $ 2,288 AROs reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and natural gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.

Transactions With Related Parti

Transactions With Related Parties	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Transactions with Related Parties	Note 12—Transactions with Related Parties Founder Shares On November 6, 2015, the Company’s Sponsor purchased 11,500,000 shares of Class B Common Stock, the founder shares, from the Company, for an aggregate purchase price of $25,000 , or approximately $0.002 per share. In February 2016, the Company’s Sponsor transferred 40,000 founder shares to each of the Company’s then independent directors (together with the Company’s Sponsor, the "initial stockholders") at their original purchase price. On February 24, 2016, the Company effected a stock dividend of approximately 0.125 shares for each outstanding share of Class B Common Stock, resulting in the initial stockholders holding an aggregate of 12,937,000 founder shares. On April 8, 2016, following the expiration of the underwriters' remaining over-allotment option in connection with the Company’s IPO, the Company’s Sponsor forfeited 437,500 founder shares, so that the remaining 12,500,000 founder shares held by the initial stockholders would represent 20% of the Company’s then issued and outstanding shares of common stock. On October 11, 2016, all of the outstanding founder shares were automatically converted into shares of Class A Common Stock on a one -for-one basis in connection with the closing of the Business Combination. The initial stockholders have agreed, subject to limited exceptions, not to transfer, assign or sell any of their shares of Class A Common Stock received upon conversion of their founder shares until the earlier to occur of: (A) one year after the closing of the Business Combination or (B) subsequent to the Business Combination, (x) if the last sale price of the Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30 trading day period commencing at least 150 days after the closing of the Business Combination, or (y) the date on which the Company completes a liquidation, merger, stock exchange or other similar transaction that results in all of its stockholders having the right to exchange their shares of common stock for cash, securities or other property. Administrative Support Agreement On February 23, 2016, the Company entered into an administrative support agreement pursuant to which it agreed to pay an affiliate of its Sponsor a total of $10,000 per month for office space, utilities and secretarial and administrative support. The Company paid the affiliate of the Sponsor $70,000 for such services for the nine months ended September 30, 2016. Following the closing of the Business Combination, the Company no longer pays these monthly fees. Private Placement Warrants On February 29, 2016, the Company’s Sponsor purchased 8,000,000 Private Placement Warrants from the Company at a price of $1.50 per whole warrant ( $12.0 million in the aggregate) in a private placement that occurred simultaneously with the closing of the Company’s IPO. Each whole Private Placement Warrant is exercisable for one whole share of Class A Common Stock at a price of $11.50 per share. A portion of the purchase price of the Private Placement Warrants was placed in the Company’s trust account along with the proceeds from its IPO. The Private Placement Warrants are non-redeemable and exercisable on a cashless basis so long as they are held by the Company’s Sponsor or its permitted transferees. Related Party Loans On November 6, 2015, the Company’s Sponsor agreed to loan it an aggregate of up to $300,000 to cover expenses related to its IPO pursuant to a promissory note (the "2015 Note"). The 2015 Note was non-interest bearing and payable on the earlier of March 31, 2016 or the completion of the Company’s IPO. On November 10, 2015, the Company borrowed $150,000 under the 2015 Note, and it borrowed the remaining $150,000 under the 2015 Note in February 2016. On February 29, 2016, the full $300,000 balance of the 2015 Note was repaid to the Company’s Sponsor. On August 2, 2016, the Company issued an unsecured, non-interest bearing promissory note to its Sponsor (the “2016 Note”). The Company borrowed $300,000 under the 2016 Note, and repaid the full $300,000 balance upon the closing of the Business Combination on October 11, 2016. Exchange Right On October 11, 2016, following the closing of the Business Combination, the Company issued 844,079 shares of its Class A Common Stock, par value $0.0001 per share, to an accredited investor at the direction of members of CRP affiliated with such investor (the “CRP Members”), in exchange for 844,079 common membership interests in CRP (the “CRP Common Units”) held by certain Centennial Contributors. The exchange was effected in accordance with the Fifth Amended and Restated Limited Liability Company Agreement of CRP, which permits Centennial Contributors of CRP Common Units to exchange their CRP Common Units on a one -for- one basis for shares of Class A Common Stock. Upon the exchange of the CRP Common Units described above, the Company canceled 844,079 shares of its Class C Common Stock, par value $0.0001 per share, held by the Centennial Contributors. Amended and Restated Limited Liability Company Agreement of CRP In connection with the closing of the Business Combination, on October 11, 2016, the Company and the Centennial Contributors entered into CRP’s fifth amended and restated limited liability company agreement (the “A&R LLC Agreement”). The operations of CRP, and the rights and obligations of the holders of CRP Common Units, are set forth in the A&R LLC Agreement. On December 28, 2016 and March 20, 2017, in connection with the Silverback Acquisition, the A&R LLC Agreement was amended by Amendment No. 1 to the A&R LLC Agreement and Amendment No. 2 to the A&R LLC Agreement, respectively (the “CRP Amendments”). Pursuant to the CRP Amendments, the Series B Preferred Units were created, with 104,400 of such Series B Preferred Units issued to the Company, in connection with the contribution of proceeds from the Silverback Acquisition Private Placements. Pursuant to the CRP Amendments, the Series B Preferred Units have limited voting rights and are entitled to participate with the CRP Common Units in any distributions declared in accordance with the A&R LLC Agreement. The Series B Preferred Units will automatically convert to CRP Common Units upon the conversion of the Company’s Series B Preferred Stock. Amended and Restated Registration Rights Agreement In connection with the closing of the Business Combination, on October 11, 2016, the Company entered into an amended and restated registration rights agreement (the “Registration Rights Agreement”) with its Sponsor, certain of its former and current directors, Riverstone Centennial Holdings, L.P. (“Riverstone Centennial”) and the Centennial Contributors, pursuant to which such parties are entitled to certain registration rights relating to (i) shares of the Company’s Class A Common Stock issued to our Sponsor and such former and current directors upon the conversion of their founder shares at the closing of the Business Combination, (ii) the Private Placement Warrants and warrants that may be issued upon conversion of working capital loans (and any shares of Class A Common Stock issuable upon the exercise of such warrants), (iii) the shares of Class A Common Stock that have been or may be issued from time to time to certain members of CRP who own CRP Common Units upon the redemption or exchange by such members of CRP Common Units for shares of Class A Common Stock (the “Centennial Holder Shares”) and (iv) the shares of Class A Common Stock issued to Riverstone Centennial in the Business Combination Private Placement (collectively, the “Registrable Securities”). The holders of a majority of the Registrable Securities (other than the securities identified in clauses (iii) and (iv) of the preceding paragraph) are entitled to make up to three demands, excluding short form demands, that the Company register the resale of such securities, while holders of a majority of the Registrable Securities owned by Riverstone Centennial and its permitted transferees are entitled to five demands, excluding short form demands, that the Company register the resale of such securities. Additionally, the holders of a majority of the Centennial Holder Shares are entitled to demand one underwritten offering if the offering is reasonably expected to result in gross proceeds of more than $50 million . In connection with this Amended and Restated Registration Rights Agreement, the Company filed a Registration Statement on Form S-1 that was declared effective on November 21, 2016. The holders also have certain “piggy-back” registration rights with respect to registration statements and rights to require the Company to register for resale such securities pursuant to Rule 415 under the Securities Act. However, the Registration Rights Agreement provides that the Company will not permit any registration statement filed under the Securities Act with respect to the founder shares and the Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants to become effective until termination of the applicable lock-up period, which occurs (i) in the case of the founder shares, on the earlier of (A) October 11, 2017, (B) if the last sale price of the Company’s Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions) for any 20 trading days within any 30 -trading day period commencing at least 150 days after the Business Combination, or (C) the date on which the Company completes a liquidation, merger, capital stock exchange, reorganization or other similar transaction that results in all of its stockholders having the right to exchange their shares of common stock for cash, securities or other property and (ii) in the case of the Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants, November 11, 2016. The Company will bear the expenses incurred in connection with the filing of any such registration statements. Subscription Agreements In connection with the Business Combination, on July 21, 2016, the Company entered into subscription agreements with certain investors pursuant to which such investors purchased, in the aggregate, 20,000,000 shares of Class A Common Stock at the closing of the Business Combination for an aggregate purchase price of $200.0 million . On the same date, the Company entered into a separate subscription agreement with Riverstone Centennial, pursuant to which Riverstone Centennial purchased 81,005,000 shares of Class A Common Stock at the closing of the Business Combination for an aggregate purchase price of approximately $810.0 million . In connection with the Silverback Acquisition, on November 27, 2016 (as amended on December 22, 2016), the Company entered into a subscription agreement with the Riverstone Purchasers, pursuant to which the Riverstone Purchasers agreed to purchase an aggregate of 3,473,590 shares of Class A Common Stock and 104,400 shares of Series B Preferred Stock at the closing for an aggregate purchase price of approximately $430.0 million . In addition, on December 2, 2016, the Company entered into subscription agreements with the other selling stockholders, pursuant to which such selling stockholders agreed to purchase an aggregate of 33,012,380 shares of Class A Common Stock at the closing for an aggregate purchase price of approximately $480.0 million . The Company refers to the subscription agreements entered into by the selling stockholders, including the Riverstone Purchasers, as the “Subscription Agreements.” The shares of Class A Common Stock and Series B Preferred Stock issued pursuant to the Subscription Agreements were not registered under the Securities Act in reliance upon the exemption provided in Section 4(a)(2) of the Securities Act. The Subscription Agreements provide that the Company must register the resale of the shares of Class A Common Stock issued thereunder pursuant to a registration statement that must be filed within 75 calendar days after consummation of the Silverback Acquisition. The Subscription Agreements provide further that the Company must use its commercially reasonable efforts to have the registration statement declared effective as soon as practicable after the filing thereof, but no later than the earlier of (i) the 90th calendar day following the filing thereof and (ii) the 10th business day after the date the Company is notified (orally or in writing, whichever is earlier) by the SEC that such registration statement will not be “reviewed” or will not be subject to further review. Customer and Supplier Relationships NGP Affiliated Companies In May 2016, the Company acquired acreage in close proximity to its operating area in Reeves County, Texas and wellbore only rights in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB, LLC, an affiliate of NGP. From time to time, the Company obtains services related to its drilling and completion activities from affiliates of NGP. In particular, the Company has paid the following amounts to the following affiliates of NGP for such services: (i) approximately $0.5 million during the year ended December 31, 2016 to Cretic Energy Services, LLC (“Cretic”); and (ii) approximately $3.3 million during the year ended December 31, 2016 to RockPile Energy Services, LLC. On September 8, 2016, Rockpile Energy Services, LLC, was purchased from NGP by an unrelated third party. At December 31, 2016 , included in Accounts payable and accrued expenses was $0.2 million due to Cretic. The Company is party to a 15 -year gas gathering agreement with PennTex Permian, LLC (“PennTex”), which terminates on April 1, 2029 and is subject to one -year extensions at either party’s election. Under the agreement, PennTex gathers and processes the Company’s gas. PennTex purchases the extracted natural gas liquids from the Company, net of gathering fees and an agreed percentage of the actual proceeds from the sale of the residue natural gas and natural gas liquids. Net payments received from PennTex for the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) and the years ended December 31, 2015 and 2014 were $0.2 million , $1.0 million , $1.2 million and $2.2 million , respectively. In the third quarter of 2016, PennTex sold its assets related to this agreement to an unrelated third party In October 2014, the gas gathering agreement with PennTex was amended to construct an expansion of the gathering system and a receipt point. Please refer to Note 13—Commitments and Contingencies . Riverstone Affiliated Companies From time to time, the Successor obtains services related to its drilling and completion activities from affiliates of Riverstone. In particular, the Successor has paid the following amounts to the following affiliates of Riverstone for such services: (i) approximately $ 8.2 million during the year ended December 31, 2016 to Liberty Oilfield Services, LLC (“Liberty”); and (ii) approximately $ 1.4 million during the year ended December 31, 2016 to Permian Tank and Manufacturing, Inc. (“Permian”). At December 31, 2016 , included in Accounts payable and accrued expenses was $3.1 million and $0.4 million due to Liberty and Permian, respectively. Other Affiliated Companies Mark G. Papa, our President, Chief Executive Officer and Chairman of the Board, serves as a director and Chairman of the Board of Oil States International, Inc., an energy services company publicly traded on the New York Stock Exchange (“Oil States”). From time to time, the Successor obtains services related to drilling and completion activities from Oil States. In particular, during the fiscal year ended December 31, 2016 , the Successor paid approximately $1.2 million to Oil States. At December 31, 2016 , included in Accounts payable and accrued expenses was $0.2 million due to Oil States.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13—Commitments and Contingencies Operating Leases and Other Commitments The following is a schedule of the Company’s future minimum lease payments with commitments that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2016 : Amount Years ending December 31, (in thousands) 2017 $ 8,147 2018 814 2019 573 2020 134 2021 79 Thereafter 7,226 Total $ 16,973 Financing Obligation In October 2014, the Company’s gas gathering agreement with PennTex was amended to construct an expansion of the gathering system and a receipt point. The Company reimbursed PennTex for the total cost of the expansion project. The Company paid a minimum fee of $7,000 per day until PennTex recouped the capital outlay for the expansion project. At December 31, 2016 , the financing obligation was paid in full. At December 31, 2015 , a short-term liability of $2.1 million was in included in Other current liabilities on the consolidated balance sheets. For the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) and for the year ended December 31, 2015 , the Company made payments, including interest, of $0.1 million , $2.1 million and $1.7 million , respectively. Transportation and Gathering Agreement In December 2015, the Company entered into a transportation and gathering services agreement by which a transporter agreed to construct a crude oil gathering and transportation system capable of transporting crude oil from certain Company wells in Reeves and Ward Counties, Texas to destination points in Crane and Midland, Texas (the “Transportation System”), and the Company agreed to dedicate and ship on the Transportation System all crude oil owned or controlled by the Company from oil and gas leases covering approximately 28,000 gross acres located within a designated area of mutual interest in Reeves and Ward Counties. The agreement has a primary term of 12 years from October 1, 2016, the date the Transportation System was first put into service, and may be extended at the Company’s option for two successive two -year terms and, thereafter, is automatically extended for successive one -year terms unless terminated by the Company or the transporter upon 60 days’ prior notice. Purchase Agreement In July 2016, the Company entered into a crude oil purchase agreement by which the Company agreed to sell all of its crude oil production that is produced at receipt points identified in the agreement commencing on the October 1, 2016 in-service date of the Transportation System. The purchaser is obligated to purchase the crude oil at the receipt points identified in the agreement and transport it on the Transportation System. The agreement has an initial term of nine months from October 1, 2016, the date the Transportation System entered commercial service, and evergreen 30 -day renewal terms unless terminated by the Company or the purchaser on 30 days’ prior notice. The price received by the Company for the crude oil it sells under the agreement is based generally on NYMEX pricing subject to marketing and other adjustments, and varies depending on whether the oil is transported to Crane or Midland, Texas and on whether the oil is transported before or after the Transportation System is connected to a pipeline in Crane, Texas or a terminal in Midland, Texas. Drilling Rig Contracts As of December 31, 2016 , the Company has four drilling rigs under contract. All of these contracts expire in 2017. In light of the low commodity price environment, the Company curtailed its drilling activity during 2015. For the year-ended December 31, 2015 , the Company incurred drilling rig termination fees of $2.4 million , which are recorded in the Contract termination and rig stacking line item in the accompanying consolidated and combined statements of operations. Office Leases The Company leases office space in Denver, Colorado, Midland, Texas, Sugar Land, Texas, and Pecos, Texas. The Company recognized rent expense of $0.1 million , $0.4 million , $0.4 million and $0.5 million for the periods from October 11, 2016, through December 31, 2016 , January 1, 2016, through October 10, 2016 , and for the years ended December 31, 2015 and December 31, 2014 , respectively. Contingencies In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Management is unaware of any pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of these consolidated financial statements.

Supplemental Information About

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) (Notes)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Information About Oil & Natural Gas Producing Activities	Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) Costs Incurred For Oil and Natural Gas Producing Activities The following table sets forth the capitalized costs incurred in the Company’s oil and gas production, exploration, and development activities: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Acquisition costs: Proved properties $ 561,251 $ 16,386 $ 14,268 $ 5,758 Unproved properties 1,905,660 39,399 28,955 16,409 Development costs 44,602 53,512 87,452 324,802 Exploration costs 844 — 84 — Total $ 2,512,357 $ 109,297 $ 130,759 $ 346,969 Results of Oil and Natural Gas Producing Activities The results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Revenues: Oil, natural gas and NGL sales $ 29,717 $ 69,116 $ 90,460 $ 131,825 Costs: Lease operating expenses 3,541 11,036 21,173 17,690 Severance and ad valorem taxes 1,636 3,696 5,021 6,875 Transportation, processing, gathering and other operating expenses 2,187 4,583 5,732 4,772 Depletion, amortization and accretion of asset retirement obligations 14,486 62,228 89,350 68,981 Abandonment expense and impairment of unproved properties — 2,545 7,619 20,025 Exploration 844 — 84 — Contract termination and rig stacking — — 2,387 — Income tax expense (benefit) — (406 ) (572 ) 1,524 Results of operations $ 7,023 $ (14,566 ) $ (40,334 ) $ 11,958 Oil and Gas Reserve Quantities The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and natural gas producing activities and Securities and Exchange Commission (“SEC”) rules for oil and natural gas reporting reserves estimation and disclosure. Estimates of the Company’s proved oil and natural gas reserves at December 31, 2016 , 2015 and 2014 were prepared by Netherland, Sewell & Associates, Inc. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The following table summarizes the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month for the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) and for the years ended December 31, 2015 and 2014 . The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows (“standardized measure”): Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 2014 Oil (per Bbl) $ 38.49 $ 36.98 $ 41.85 $ 84.94 Gas (per Mcf) 0.98 1.24 1.71 4.70 NGLs (per Bbl) 14.59 13.28 13.94 22.70 The table below presents a summary of changes in the Company’s estimated proved reserves: Successor Predecessor October 11, 2016, through December 31, 2016 January 1, 2016, through October 10, 2016 Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Total proved reserves: Beginning of period 30,091 36,801 4,506 23,199 32,442 3,851 Extensions and discoveries 7,063 12,219 1,225 5,851 6,410 773 Revisions of previous estimates 184 16,445 983 1,025 (1,521 ) (110 ) Purchases of reserves in place 9,651 83,992 5,152 1,600 2,130 245 Divestitures of reserves in place — — — — — — Production (523 ) (1,113 ) (96 ) (1,584 ) (2,660 ) (253 ) End of period 46,466 148,344 11,770 30,091 36,801 4,506 Proved developed reserves: Beginning of period 11,346 14,973 1,927 9,347 12,711 1,603 End of period 14,551 42,190 3,618 11,346 14,973 1,927 Proved undeveloped reserves: Beginning of period 18,745 21,828 2,579 13,852 19,731 2,248 End of period 31,914 106,154 8,152 18,745 21,828 2,579 Predecessor Year Ended December 31, 2015 Year Ended December 31, 2014 Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Total proved reserves: Beginning of period 19,850 27,414 1,551 18,510 6,968 525 Extensions and discoveries 9,444 11,927 1,432 16,122 22,575 1,127 Revisions of previous estimates (5,109 ) (5,204 ) 995 56 178 180 Purchases of reserves in place 844 1,363 204 162 192 23 Divestitures of reserves in place — — — (13,572 ) (387 ) (69 ) Production (1,830 ) (3,058 ) (331 ) (1,428 ) (2,112 ) (235 ) End of period 23,199 32,442 3,851 19,850 27,414 1,551 Proved developed reserves: Beginning of period 8,026 11,959 766 6,021 4,837 382 End of period 9,347 12,711 1,603 8,026 11,959 766 Proved undeveloped reserves: Beginning of period 11,823 15,455 785 12,489 2,131 143 End of period 13,852 19,731 2,248 11,823 15,455 785 Proved reserves at December 31, 2016 increased 104% to 82,959 MBoe, compared to 40,730 MBoe at October 10, 2016. During the period from October 11, 2016, through December 31, 2016 (Successor) , the Company acquired 28,801 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions . Additionally, the Company added 10,324 MBoe of proved reserves through extensions, primarily due to its drilling activity, as well as, 3,908 MBoe of revisions due to improved results in completion techniques and adjustments of natural gas and NGL treatment through the gas plants slightly offset by 805 MBoe of production. Proved reserves at October 10, 2016 increased 25% to 40,730 MBoe, compared to 32,457 MBoe at December 31, 2015. During the period from January 1, 2016, through October 10, 2016 (Predecessor) , the Company acquired 2,200 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions . Additionally, the Company added 7,692 MBoe of proved reserves through extensions, primarily due to its drilling activity, as well as 660 MBoe due to positive performance revisions, slightly offset by 2,280 MBoe of production. Proved reserves at December 31, 2015 increased 25% to 32,457 MBoe, compared to 25,970 MBoe at December 31, 2014. During 2015, the Company added 12,864 MBoe of proved reserves through extensions, primarily due to its drilling activity. During 2015, the Company had net negative revisions of 4,981 MBoe. The significant decrease in commodity prices seen in 2015 resulted in negative revisions related to the conversion of approximately 6,794 MBoe from PUDs to unproved reserves, partially offset by a positive revision in performance. During 2015, the Company acquired 1,275 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions . During 2014, the Company added 21,012 MBoe of proved reserves through extensions and discoveries, primarily due to its continued development drilling program and 265 MBoe of proved reserves, due to better than expected performance of its proved developed reserves. During 2014, the Company divested of 13,706 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions . Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%. It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of its’ Predecessor’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves. The following table presents the Company’s standardized measure of discounted future net cash flows: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Future cash inflows $ 2,105,585 $ 1,217,641 $ 1,079,962 $ 1,850,205 Future development costs (482,162 ) (297,559 ) (277,837 ) (440,366 ) Future production costs (640,306 ) (413,410 ) (450,058 ) (457,236 ) Future income tax expenses (136,587 ) (5,614 ) (6,643 ) (10,834 ) Future net cash flows 846,530 501,058 345,424 941,769 10% discount to reflect timing of cash flows (471,438 ) (291,345 ) (210,355 ) (575,886 ) Standardized measure of discounted future net cash flows $ 375,092 $ 209,713 $ 135,069 $ 365,883 The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Successor Predecessor (in thousands) October 11, 2016 January 1, 2016 Standardized measure of discounted future net cash flows, beginning of period $ 209,713 $ 135,069 Sales of oil, natural gas and NGLs, net of production costs (22,354 ) (49,801 ) Purchase of minerals in place 127,842 10,145 Divestiture of minerals in place — — Extensions and discoveries, net of future development costs 55,825 46,438 Change in estimated development costs 10,891 11,743 Net change in prices and production costs (978 ) 6,661 Change in estimated future development costs 571 28,998 Revisions of previous quantity estimates 20,190 3,673 Accretion of discount 4,753 11,319 Net change in income taxes (47,990 ) (1,568 ) Net change in timing of production and other 16,629 7,036 Standardized measure of discounted future net cash flows, end of period $ 375,092 $ 209,713 Predecessor Year Ended December 31, (in thousands) 2015 2014 Standardized measure of discounted future net cash flows, beginning of period $ 365,883 $ 371,307 Sales of oil, natural gas and NGLs, net of production costs (58,534 ) (102,488 ) Purchase of minerals in place 14,416 5,650 Divestiture of minerals in place — (242,344 ) Extensions and discoveries, net of future development costs 57,894 312,532 Change in estimated development costs 16,100 10,386 Net change in prices and production costs (494,734 ) (3,027 ) Change in estimated future development costs 247,642 2,935 Revisions of previous quantity estimates (51,342 ) 924 Accretion of discount 37,517 13,561 Net change in income taxes 1,601 (2,762 ) Net change in timing of production and other (1,374 ) (791 ) Standardized measure of discounted future net cash flows, end of period $ 135,069 $ 365,883

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Selected Quarterly Financial Data	Selected Quarterly Financial Data (Unaudited) Predecessor Successor Periods Ended Period Ended (in thousands) March 31 June 30 September 30 October 1, 2016 October 11, 2016 2016 Revenues $ 15,121 $ 23,347 $ 27,321 $ 3,327 $ 29,717 Operating expenses 29,855 30,251 32,228 183,465 36,800 Gain (loss) on sale of oil and natural gas properties (4 ) — 15 — 24 Operating loss (14,738 ) (6,904 ) (4,892 ) (180,138 ) (7,059 ) Other income (expense) 277 (9,635 ) (242 ) (2,858 ) (1,926 ) Income tax expense (benefit) — 406 — — — Net loss (14,461 ) (16,133 ) (5,134 ) (182,996 ) (8,081 ) Loss per share: Basic $ (0.05 ) Diluted $ (0.05 ) Predecessor Quarters Ended (in thousands) March 31 June 30 September 30 December 31 2015 Revenues $ 24,416 $ 22,431 $ 21,893 $ 21,720 Operating expenses 36,656 37,184 30,442 42,024 Gain (loss) on sale of oil and natural gas properties 2,675 4 9 (249 ) Operating loss (9,565 ) (14,749 ) (8,540 ) (20,553 ) Other income (expense) 3,628 (7,922 ) 11,866 6,938 Income tax expense — — — 572 Net (loss) income (5,937 ) (22,671 ) 3,326 (13,043 )

Basis of Presentation and Sum22

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated and combined financial statements. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2016 , through the filing date of this report. As a result of the Business Combination, the Company is the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. The Company’s financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016. The Merger was accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of the net assets acquired. Refer to Note 2—Business Combination for further discussion of the Business Combination. As a result of the application of the acquisition method of accounting as of the Business Combination, the financial statements for the Predecessor period and for the Successor period are presented on a different basis of accounting and are therefore, not comparable.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements included herein have been prepared in accordance with GAAP and the rules and regulations of Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP, and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates	Use of Estimates The preparation of the Company’s consolidated and combined financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established. The more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank.
Accounts Receivable	Accounts Receivable Accounts receivable consists mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months and the Company has had minimal bad debts. Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company establishes an allowance for doubtful accounts equal to the estimable portions of accounts receivable for which failure to collect is probable.
Oil and Natural Gas Properties	The Company reviews it proved oil and natural gas properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to income. Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or otherwise attributed to the property. Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells and development wells are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.
Other Property and Equipment	Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, vehicles, and computer hardware and software is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets ranging from three to twenty years. Major renewals and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.
Deferred Loan Costs	Deferred Loan Costs Deferred loan costs related to the Company’s revolving credit facility are included in the line item Other noncurrent assets in the consolidated balance sheets and are stated at cost, net of amortization. These costs are amortized to interest expense on a straight line basis over the borrowing term.
Derivative Financial Instruments	Derivative Financial Instruments In order to manage its exposure to oil and natural gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements relating to the price risk associated with a portion of its production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position. The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. The Company’s derivatives have not been designated as hedges for accounting purposes. For additional discussion on derivatives, please refer to Note 9—Derivative Instruments .
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and natural gas properties in the accompanying consolidated balance sheets. The Company depletes the amount added to proved oil and natural gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. For additional discussion, please refer to Note 11—Asset Retirement Obligations .
Revenue Recognition	Revenue Recognition The Company derives revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company follows the sales method of accounting for its oil and natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves.
Income Taxes	Income Taxes Income taxes and uncertain tax positions are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 740, Accounting for Income Taxes (“ASC 740”). Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth in ASC 740. A valuation allowance is established when necessary to reduce deferred tax assets to the amount expected to be realized.
Equity Based Compensation	Equity Based Compensation (Successor) The Company recognizes compensation related to all stock-based awards, including stock options, in the financial statements based on their estimated grant-date fair value. The Company grants various types of stock-based awards including stock options and restricted stock. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock are valued using the market price of the Company’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 8—Equity Based Compensation for additional information regarding the Company’s equity based compensation (successor). Equity Based Compensation (Predecessor) Pursuant to the LLC Agreement of CRP (prior to the Business Combination), certain incentive units were available to be issued to the Company’s management and employees, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The incentive units were intended to be compensation for services rendered to CRP. Tier Incentive units are accounted for as liability awards under FASB ASC Topic 718, Compensation: Stock Compensation (“ASC 718”) , with compensation expense based on period-end fair value. Refer to Note 8—Equity Based Compensation for additional information regarding the CRP’s equity based compensation (Predecessor).
Earnings (Loss) Per Share	Earnings (Loss) Per Share The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Basic earnings (loss) per share is calculated by dividing earnings (loss) available to common shareholders by the weighted average shares-basic during each period. The Company’s preferred series B shares have a non-forfeitable right to participate in distributions with common stockholders on a pro rata, as-converted basis and as such are considered participating securities. Shares of the Company’s unvested restricted stock are eligible to receive dividends; however, dividend rights will be forfeited if the award does not vest. Accordingly, these shares are not considered participating securities. Shares of the Company’s class C common stock and warrants do not share in the earnings or losses and are therefore not participating securities. The Company uses the "if-converted" method to determine the potential dilutive effect of exchanges of outstanding CRP Common Units and corresponding shares of its outstanding Class C common stock, and the treasury stock method to determine the potential dilutive effect of its outstanding restricted stock and stock options.
Segment Reporting	Segment Reporting The Company operates in only one industry segment which is the exploration and production of oil and natural gas. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update should be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of the Company’s cash flows and will not have a material impact on its consolidated financial statements. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing . This update clarifies two principles of ASC Topic 606, Revenue from Contracts with Customers : identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net) , the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Company’s financial position, results of operations and liquidity. March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation . This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net) . Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of this update will have on its financial position, results of operations and liquidity. In February 2016, the FASB issued ASU 2016-02, Leases . This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on its balance sheet for current operating leases. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application permitted for annual reporting period beginning after December 31, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

Basis of Presentation and Sum23

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	Successor October 11, 2016 (in thousands, except per share data) Net income (loss) $ (8,081 ) Less: Loss allocable to participating securities (46 ) Net loss available for common shareholders $ (8,035 ) Basic net loss per share $ (0.05 ) Diluted net loss per share $ (0.05 ) Basic weighted average share outstanding 165,684 Add: Dilutive effects of stock options and RSUs — Diluted weighted average shares outstanding 165,684

Business Combination (Tables)

Business Combination (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The purchase consideration for the Business Combination was as follows: (in thousands) October 11, 2016 Preliminary purchase consideration: Cash $ 1,186,744 Repayment of CRP long-term debt(1) 189,000 Total purchase price consideration 1,375,744 Fair value of non-controlling interest(2) 184,779 Total purchase price consideration and fair value of non-controlling interest $ 1,560,523 (1) Represents the additional contribution made by Silver Run to CRP in exchange for units representing common membership interest in CRP ("CRP Common Units"), to repay CRP's outstanding indebtedness at the Closing Date. (2) Represents the fair value of the non-controlling interest (NCI) attributable to the Centennial Contributors. NCI is the portion of equity (net assets) in a subsidiary not attributable, directly or indirectly to Silver Run. In a business combination the NCI is recognized at its acquisition date fair value in accordance with ASC 805. The fair value of the NCI represents a 11% membership interest in CRP. Predecessor (in thousands) June 3, 2016 Cash consideration $ 32,979 Fair value of assets and liabilities acquired: Proved oil and natural gas properties 15,374 Unproved oil and natural gas properties 18,071 Total fair value of oil and natural gas properties acquired 33,445 Revenue Suspense (400 ) Asset retirement obligation (66 ) Total fair value of net assets acquired $ 32,979 The Company allocated the final purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. Predecessor Acquisition #1 Acquisition #2 (in thousands) September 1, 2015 September 3, 2015 Cash consideration $ 16,006 $ 6,369 Fair value of assets and liabilities acquired: Proved oil and natural gas properties 7,731 6,491 Unproved oil and natural gas properties 8,312 — Total fair value of oil and natural gas properties acquired 16,043 6,491 Asset retirement obligation (37 ) (122 ) Total fair value of net assets acquired $ 16,006 $ 6,369
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the allocation of the purchase consideration to the assets acquired and liabilities assumed: (in thousands) October 11, 2016 Fair value of assets acquired: Other current assets $ 13,341 Derivative instruments 1,052 Oil and gas properties(1): Proved properties 444,551 Unproved properties 1,138,423 Other property, plant and equipment 1,764 Goodwill — Total fair value of assets acquired 1,599,131 Fair value of liabilities assumed: Accounts payable and accrued expenses 30,156 Other current liabilities 63 Derivative instruments(2) 3,400 Asset retirement obligation 4,989 Fair value of net assets acquired $ 1,560,523 (1) The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. The reduction in the carrying cost of the proved properties was impacted by all of these factors, but most notably, the assumptions with respect to future commodity prices as of the valuation date. (2) The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s own nonperformance risk, each based on the current published credit default swap rates.
Business Acquisition, Pro Forma Information	The following unaudited pro forma combined financial information has been prepared as if the Business Combination and other related transactions had taken place on January 1, 2015. The unaudited pro forma consolidated financial information has been prepared using the acquisition method of accounting in accordance with GAAP. The information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including depletion of CRP’s fair-valued proved oil and gas properties, and the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2016, were adjusted to exclude $18.7 million of transaction-related costs and $165.4 million of incentive unit compensation incurred by CRP. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Business Combination taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results. (Unaudited Pro Forma) Year Ended December 31, (in thousands) 2016 2015 Total revenues $ 98,833 $ 90,460 Total operating expenses 86,490 123,702 Net income (loss) attributable to common shareholders of Centennial Resource Development, Inc. 1,666 (6,397 ) Basic and diluted net loss per share 0.01 (0.04 )

Property Acquisitions and Dis25

Property Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The purchase consideration for the Business Combination was as follows: (in thousands) October 11, 2016 Preliminary purchase consideration: Cash $ 1,186,744 Repayment of CRP long-term debt(1) 189,000 Total purchase price consideration 1,375,744 Fair value of non-controlling interest(2) 184,779 Total purchase price consideration and fair value of non-controlling interest $ 1,560,523 (1) Represents the additional contribution made by Silver Run to CRP in exchange for units representing common membership interest in CRP ("CRP Common Units"), to repay CRP's outstanding indebtedness at the Closing Date. (2) Represents the fair value of the non-controlling interest (NCI) attributable to the Centennial Contributors. NCI is the portion of equity (net assets) in a subsidiary not attributable, directly or indirectly to Silver Run. In a business combination the NCI is recognized at its acquisition date fair value in accordance with ASC 805. The fair value of the NCI represents a 11% membership interest in CRP. Predecessor (in thousands) June 3, 2016 Cash consideration $ 32,979 Fair value of assets and liabilities acquired: Proved oil and natural gas properties 15,374 Unproved oil and natural gas properties 18,071 Total fair value of oil and natural gas properties acquired 33,445 Revenue Suspense (400 ) Asset retirement obligation (66 ) Total fair value of net assets acquired $ 32,979 The Company allocated the final purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. Predecessor Acquisition #1 Acquisition #2 (in thousands) September 1, 2015 September 3, 2015 Cash consideration $ 16,006 $ 6,369 Fair value of assets and liabilities acquired: Proved oil and natural gas properties 7,731 6,491 Unproved oil and natural gas properties 8,312 — Total fair value of oil and natural gas properties acquired 16,043 6,491 Asset retirement obligation (37 ) (122 ) Total fair value of net assets acquired $ 16,006 $ 6,369

Accounts Receivable, Accounts26

Accounts Receivable, Accounts Payable and Accrued Expenses (Tables)	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Schedule of Accounts, Notes, Loans and Financing Receivable	Accounts receivable are comprised of the following: Successor Predecessor (in thousands) December 31, 2016 December 31, 2015 Oil and natural gas $ 11,596 $ 5,789 Joint interest billings 2,942 1,514 Hedge settlements 194 3,956 Other 2 1,844 Allowance for doubtful accounts — (91) Accounts receivable, net $ 14,734 $ 13,012
Schedule of Accounts Payable and Accrued Liabilities	Accounts payable and accrued expenses are comprised of the following: Successor Predecessor (in thousands) December 31, 2016 December 31, 2015 Accounts payable $ 11,210 $ 1,827 Accrued capital expenditures 24,038 11,700 Revenues payable 3,815 3,439 Payable to Silverback 32,293 — Accrued underwriting fees 7,719 — Other 7,025 3,019 Accounts payable and accrued expenses $ 86,100 $ 19,985

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Debt	The term loan, net of unamortized deferred financing costs on the accompanying consolidated balance sheets as of December 31, 2015 , consisted of the following: Predecessor (in thousands) December 31, 2015 Term loan $ 65,000 Unamortized deferred financing costs (351) Term loan, net of unamortized deferred financing costs $ 64,649

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Income tax benefit (expense) are included in the consolidated statements of operations are detailed below: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Current taxes Federal $ — $ — $ — $ — State — — — — — — — — Deferred taxes Federal — — — — State — 406 572 (1,524 ) — 406 572 (1,524 ) Income tax benefit (expense) $ — $ 406 $ 572 $ (1,524 )
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the statutory federal income tax expense to the income tax expense from continuing operations provided at December 31, 2016, is as follows: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Income tax (benefit) expense at the federal statutory rate $ (3,145 ) $ — $ — $ — State income taxes - net of federal income tax benefits — 406 572 (1,524 ) Excess depletion — — — — Noncontrolling interest in partnership 273 — — — Nondeductible expenses 4 — — — Change in valuation allowance 2,868 — — — Income tax benefit (expense) $ — $ 406 $ 572 $ (1,524 )
Schedule of Deferred Tax Assets and Liabilities	The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below: Successor Predecessor (in thousands) December 31, 2016 December 31, 2015 Deferred tax assets: Net operating loss carryforwards $ 2,590 $ — Capitalized intangible drilling cost 10,314 — Equity-based compensation 467 — Other assets 291 — Total deferred tax assets 13,662 — Deferred tax liabilities: Investment in Centennial Resource Production, LLC (8,514 ) — Other liabilities — (2,361 ) Total deferred tax liabilities (8,514 ) (2,361 ) Valuation allowance (5,148 ) — Net deferred tax asset (liabilities) $ — $ (2,361 )

Shareholders' and Owners Equi29

Shareholders' and Owners Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Noncontrolling Interest	The following table summarizes the noncontrolling interest income (loss): Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 2014 Net loss attributable to noncontrolling interest $ (904 ) $ — $ — $ (2 )

Equity Based Compensation (Tabl

Equity Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan	The Company has recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Successor October 11, 2016 (in thousands) Restricted stock awards $ 405 Stock option awards 928 Total equity based compensation expense $ 1,333
Nonvested Restricted Stock Shares Activity	The following table provides information about restricted stock awards granted in 2016 : Successor Awards Weighted Average Grant-Date Fair Value Service-based stock awards: Outstanding as of October 11, 2016 — $ — Vested — $ — Granted 256,597 $ 20.03 Canceled — $ — Outstanding as of December 31, 2016 256,597 $ 20.03
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The following summarizes the options granted and related information, and the assumptions used to determine the fair value of those options. Successor October 11, 2016 Options granted 2,760,500 Weighted average grant-date fair value $ 5.93 Weighted average exercise price $ 14.67 Total fair value (in thousands) $ 16,375 Expected term 6 Expected stock volatility 40.0 % Dividend yield — % Risk-free interest rate 1.5 %
Schedule of Share-based Compensation, Stock Options, Activity	Information about outstanding stock options is summarized in the table below: Options Weighted Average Exercise Price Weighted Average Remaining Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding as of October 11, 2016 — $ — — — Exercised — $ — — — Granted 2,760,500 $ 14.67 5.8 $ 13,934 Forfeited (25,000 ) $ 14.52 5.8 $ 130 Outstanding as of December 31, 2016 2,735,500 $ 14.67 5.8 $ 13,804 Exercisable as of December 31, 2016 — $ — — $ — The following summary reflects the status of non-vested stock options as of December 31, 2016 and changes since the Business Combination on October 11, 2016 : Options Weighted Average Grant-Date Fair Value Weighted Average Exercise Price Non-vested as of October 11, 2016 — $ — $ — Vested — $ — $ — Granted 2,760,500 $ 5.93 $ 14.67 Forfeited (25,000 ) $ 5.86 $ 14.52 Non-vested as of December 31, 2016 2,735,500 $ 5.93 $ 14.67

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Schedule of Derivative Instruments	The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of December 31, 2016 : 2017 2018 Crude Oil Swaps: Notional volume (Bbl) 675,250 36,500 Weighted average fixed price ($/Bbl) $ 50.41 $ 55.95 Crude Oil Basis Swaps: Notional volume (Bbl) 127,750 — Weighted average fixed price ($/Bbl) $ (0.20 ) $ — Natural Gas Swaps: Notional volume (MMBtu) 1,460,000 — Weighted average fixed price ($/MMBtu) $ 2.94 $ —
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following tables below summarize the gross fair value of derivative assets and liabilities and the effect of netting on the consolidated balance sheets (in thousands): Successor December 31, 2016 Balance Sheet Classification Gross Amounts Netting Adjustments Net Amounts Presented on the Consolidated Balance Sheets Assets Derivative instruments Current assets $ 739 $ (308 ) $ 431 Derivative instruments Noncurrent assets — — — Total assets $ 739 $ (308 ) $ 431 Liabilities Derivative instruments Current liabilities $ 5,669 $ (308 ) $ 5,361 Derivative instruments Noncurrent Liabilities 20 — 20 Total liabilities $ 5,689 $ (308 ) $ 5,381 Predecessor December 31, 2015 Balance Sheet Classification Gross Amounts Netting Adjustments Net Amounts Presented on the Consolidated Balance Sheets Assets Derivative instruments Current assets $ 19,469 $ (426 ) 19,043 Derivative instruments Noncurrent assets 2,071 (1 ) 2,070 Total assets $ 21,540 $ (427 ) $ 21,113
Derivative Instruments, Gain (Loss)	The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 2014 (Loss) gain on derivative instruments $ (1,548 ) $ (6,838 ) $ 20,756 $ 41,943

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Fair Value, Liabilities Measured on Recurring Basis	The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2016 and December 31, 2015 (in thousands): Successor December 31, 2016 Level 1 Level 2 Level 3 Commodity derivative liability, net(1) $ — $ 4,950 $ — Predecessor December 31, 2015 Level 1 Level 2 Level 3 Commodity derivative asset, net(1) $ — $ 21,113 $ —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The following table summarizes the changes in the Company’s asset retirement obligations for the periods presented: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 (in thousands) Asset retirement obligations, beginning of period $ 4,989 $ 2,288 $ 1,824 Liabilities incurred 187 174 133 Liabilities acquired 2,002 66 178 Liabilities settled (1 ) (42 ) — Accretion expense 49 134 139 Revision of estimated liabilities — 32 14 Asset retirement obligations, end of period $ 7,226 $ 2,652 $ 2,288

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	The following is a schedule of the Company’s future minimum lease payments with commitments that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2016 : Amount Years ending December 31, (in thousands) 2017 $ 8,147 2018 814 2019 573 2020 134 2021 79 Thereafter 7,226 Total $ 16,973

Supplemental Information Abou35

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	The following table sets forth the capitalized costs incurred in the Company’s oil and gas production, exploration, and development activities: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Acquisition costs: Proved properties $ 561,251 $ 16,386 $ 14,268 $ 5,758 Unproved properties 1,905,660 39,399 28,955 16,409 Development costs 44,602 53,512 87,452 324,802 Exploration costs 844 — 84 — Total $ 2,512,357 $ 109,297 $ 130,759 $ 346,969
Results of Operations for Oil and Gas Producing Activities Disclosure	The results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Revenues: Oil, natural gas and NGL sales $ 29,717 $ 69,116 $ 90,460 $ 131,825 Costs: Lease operating expenses 3,541 11,036 21,173 17,690 Severance and ad valorem taxes 1,636 3,696 5,021 6,875 Transportation, processing, gathering and other operating expenses 2,187 4,583 5,732 4,772 Depletion, amortization and accretion of asset retirement obligations 14,486 62,228 89,350 68,981 Abandonment expense and impairment of unproved properties — 2,545 7,619 20,025 Exploration 844 — 84 — Contract termination and rig stacking — — 2,387 — Income tax expense (benefit) — (406 ) (572 ) 1,524 Results of operations $ 7,023 $ (14,566 ) $ (40,334 ) $ 11,958
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	The following table summarizes the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month for the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) and for the years ended December 31, 2015 and 2014 . The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows (“standardized measure”): Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, 2015 2014 Oil (per Bbl) $ 38.49 $ 36.98 $ 41.85 $ 84.94 Gas (per Mcf) 0.98 1.24 1.71 4.70 NGLs (per Bbl) 14.59 13.28 13.94 22.70
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The table below presents a summary of changes in the Company’s estimated proved reserves: Successor Predecessor October 11, 2016, through December 31, 2016 January 1, 2016, through October 10, 2016 Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Total proved reserves: Beginning of period 30,091 36,801 4,506 23,199 32,442 3,851 Extensions and discoveries 7,063 12,219 1,225 5,851 6,410 773 Revisions of previous estimates 184 16,445 983 1,025 (1,521 ) (110 ) Purchases of reserves in place 9,651 83,992 5,152 1,600 2,130 245 Divestitures of reserves in place — — — — — — Production (523 ) (1,113 ) (96 ) (1,584 ) (2,660 ) (253 ) End of period 46,466 148,344 11,770 30,091 36,801 4,506 Proved developed reserves: Beginning of period 11,346 14,973 1,927 9,347 12,711 1,603 End of period 14,551 42,190 3,618 11,346 14,973 1,927 Proved undeveloped reserves: Beginning of period 18,745 21,828 2,579 13,852 19,731 2,248 End of period 31,914 106,154 8,152 18,745 21,828 2,579 Predecessor Year Ended December 31, 2015 Year Ended December 31, 2014 Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Crude Oil (MBbls) Natural Gas Natural Gas Liquids (MBbls) Total proved reserves: Beginning of period 19,850 27,414 1,551 18,510 6,968 525 Extensions and discoveries 9,444 11,927 1,432 16,122 22,575 1,127 Revisions of previous estimates (5,109 ) (5,204 ) 995 56 178 180 Purchases of reserves in place 844 1,363 204 162 192 23 Divestitures of reserves in place — — — (13,572 ) (387 ) (69 ) Production (1,830 ) (3,058 ) (331 ) (1,428 ) (2,112 ) (235 ) End of period 23,199 32,442 3,851 19,850 27,414 1,551 Proved developed reserves: Beginning of period 8,026 11,959 766 6,021 4,837 382 End of period 9,347 12,711 1,603 8,026 11,959 766 Proved undeveloped reserves: Beginning of period 11,823 15,455 785 12,489 2,131 143 End of period 13,852 19,731 2,248 11,823 15,455 785
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	The following table presents the Company’s standardized measure of discounted future net cash flows: Successor Predecessor October 11, 2016 January 1, 2016 Year Ended December 31, (in thousands) 2015 2014 Future cash inflows $ 2,105,585 $ 1,217,641 $ 1,079,962 $ 1,850,205 Future development costs (482,162 ) (297,559 ) (277,837 ) (440,366 ) Future production costs (640,306 ) (413,410 ) (450,058 ) (457,236 ) Future income tax expenses (136,587 ) (5,614 ) (6,643 ) (10,834 ) Future net cash flows 846,530 501,058 345,424 941,769 10% discount to reflect timing of cash flows (471,438 ) (291,345 ) (210,355 ) (575,886 ) Standardized measure of discounted future net cash flows $ 375,092 $ 209,713 $ 135,069 $ 365,883
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Successor Predecessor (in thousands) October 11, 2016 January 1, 2016 Standardized measure of discounted future net cash flows, beginning of period $ 209,713 $ 135,069 Sales of oil, natural gas and NGLs, net of production costs (22,354 ) (49,801 ) Purchase of minerals in place 127,842 10,145 Divestiture of minerals in place — — Extensions and discoveries, net of future development costs 55,825 46,438 Change in estimated development costs 10,891 11,743 Net change in prices and production costs (978 ) 6,661 Change in estimated future development costs 571 28,998 Revisions of previous quantity estimates 20,190 3,673 Accretion of discount 4,753 11,319 Net change in income taxes (47,990 ) (1,568 ) Net change in timing of production and other 16,629 7,036 Standardized measure of discounted future net cash flows, end of period $ 375,092 $ 209,713 Predecessor Year Ended December 31, (in thousands) 2015 2014 Standardized measure of discounted future net cash flows, beginning of period $ 365,883 $ 371,307 Sales of oil, natural gas and NGLs, net of production costs (58,534 ) (102,488 ) Purchase of minerals in place 14,416 5,650 Divestiture of minerals in place — (242,344 ) Extensions and discoveries, net of future development costs 57,894 312,532 Change in estimated development costs 16,100 10,386 Net change in prices and production costs (494,734 ) (3,027 ) Change in estimated future development costs 247,642 2,935 Revisions of previous quantity estimates (51,342 ) 924 Accretion of discount 37,517 13,561 Net change in income taxes 1,601 (2,762 ) Net change in timing of production and other (1,374 ) (791 ) Standardized measure of discounted future net cash flows, end of period $ 135,069 $ 365,883

Selected Quarterly Financial 36

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Quarterly Financial Information	Predecessor Successor Periods Ended Period Ended (in thousands) March 31 June 30 September 30 October 1, 2016 October 11, 2016 2016 Revenues $ 15,121 $ 23,347 $ 27,321 $ 3,327 $ 29,717 Operating expenses 29,855 30,251 32,228 183,465 36,800 Gain (loss) on sale of oil and natural gas properties (4 ) — 15 — 24 Operating loss (14,738 ) (6,904 ) (4,892 ) (180,138 ) (7,059 ) Other income (expense) 277 (9,635 ) (242 ) (2,858 ) (1,926 ) Income tax expense (benefit) — 406 — — — Net loss (14,461 ) (16,133 ) (5,134 ) (182,996 ) (8,081 ) Loss per share: Basic $ (0.05 ) Diluted $ (0.05 ) Predecessor Quarters Ended (in thousands) March 31 June 30 September 30 December 31 2015 Revenues $ 24,416 $ 22,431 $ 21,893 $ 21,720 Operating expenses 36,656 37,184 30,442 42,024 Gain (loss) on sale of oil and natural gas properties 2,675 4 9 (249 ) Operating loss (9,565 ) (14,749 ) (8,540 ) (20,553 ) Other income (expense) 3,628 (7,922 ) 11,866 6,938 Income tax expense — — — 572 Net (loss) income (5,937 ) (22,671 ) 3,326 (13,043 )

Basis of Presentation and Sum37

Basis of Presentation and Summary of Significant Accounting Policies (Details)	Oct. 10, 2016USD ($)	Feb. 29, 2016shares	Dec. 31, 2016USD ($)	Oct. 10, 2016USD ($)	Dec. 31, 2016USD ($)segmentgeographic_area	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 11, 2016
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Oil & gas receivable, collection period					2 months
Successor
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Allowance for doubtful accounts			$ 0		$ 0
Abandonment expense and impairment of unproved properties			0
Impairment of proved oil and gas properties			$ 0
Number of industry segments | segment					1
Number of geographic areas | geographic_area					1
Successor | Minimum
Organization, Consolidation and Presentation of Financial Statements [Line Items]
PP&E, useful life					3 years
Revenue collection period					30 days
Successor | Maximum
Organization, Consolidation and Presentation of Financial Statements [Line Items]
PP&E, useful life					20 years
Revenue collection period					90 days
Predecessor
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Allowance for doubtful accounts						$ 100,000
Abandonment expense and impairment of unproved properties				$ 2,545,000		7,619,000	$ 20,025,000
Impairment expense							13,800,000
Abandonment expense							6,200,000
Impairment of proved oil and gas properties	$ 0					$ 0	$ 0
Centennial Resource Production, LLC | Successor
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Voting interest acquired								89.10%
Common Class A | IPO | Predecessor
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Stock issued during period (in shares) | shares		1
Warrants To Purchase Class A Common Stock, IPO | IPO | Predecessor
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Warrants issued (in shares)		0.33333

Basis of Presentation and Sum38

Basis of Presentation and Summary of Significant Accounting Policies - Credit Risk and Other Concentrations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Concentration Risk [Line Items]
Derivative fair value	$ 0.7
Customer Concentration Risk | Plains Marketing, LP | Successor | Sales Revenue, Net
Concentration Risk [Line Items]
Concentration risk percent	48.00%
Customer Concentration Risk | Plains Marketing, LP | Predecessor | Sales Revenue, Net
Concentration Risk [Line Items]
Concentration risk percent		64.00%	78.00%
Customer Concentration Risk | Shell Trading (US) Company | Successor | Sales Revenue, Net
Concentration Risk [Line Items]
Concentration risk percent	22.00%
Customer Concentration Risk | Permian Transport and Trading | Successor | Sales Revenue, Net
Concentration Risk [Line Items]
Concentration risk percent	11.00%

Basis of Presentation and Sum39

Basis of Presentation and Summary of Significant Accounting Policies - Earnings Per Share (Details) - Successor $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Schedule of Earnings Per Share [Line Items]
Net loss | $	$ (8,081)
Less: Loss allocable to participating securities | $	(46)
Net loss available for common shareholders | $	$ (8,035)
Loss per share, basic (in dollars per share) | $ / shares	$ (0.05)
Income (loss) per share, diluted (in dollars per share) | $ / shares	$ (0.05)
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Basic weighted average share outstanding (in shares)	165,684
Dilutive effects of stock options and RSUs (in shares)	0
Diluted weighted average shares outstanding (in shares)	165,684
Stock option awards
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,700
Restricted stock awards
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	300

Basis of Presentation and Sum40

Basis of Presentation and Summary of Significant Accounting Policies - Subsequent Events (Details) - Subsequent Event shares in Thousands	Mar. 01, 2017$ / sharesshares
Subsequent Event [Line Items]
Common stock, shares outstanding upon exercise of warrants (in shares) | shares	253,000
Public Warrants
Subsequent Event [Line Items]
Warrant exercise price (in dollars per share)	$ 0.01
Warrants, cashless exercise, common stock issues as percent of warrants	37.60%
Warrants, number of securities called by warrant (in shares) | shares	6,270
Minimum | Public Warrants
Subsequent Event [Line Items]
Warrant, cashless exercise, average common stock price per share (in dollars per share)	$ 11.50
Maximum | Public Warrants
Subsequent Event [Line Items]
Warrant, cashless exercise, average common stock price per share (in dollars per share)	$ 18.44

Business Combination (Details)

Business Combination (Details) - Successor $ in Thousands	Oct. 11, 2016USD ($)shares
Centennial Resource Production, LLC
Business Acquisition [Line Items]
Voting interest acquired	89.10%
Total cash contribution | $	$ 1,490,000
Cash consideration | $	$ 1,186,744
Centennial Contributors | Centennial Resource Production, LLC
Business Acquisition [Line Items]
Common units outstanding (in shares) | shares	20,000,000
Centennial Resource Development | Centennial Resource Production, LLC
Business Acquisition [Line Items]
Common units outstanding (in shares) | shares	163,505,000

Business Combination - Purchase

Business Combination - Purchase Consideration (Details) - USD ($) $ in Thousands	Oct. 11, 2016	Dec. 28, 2016
Centennial Resource Production, LLC
Business Acquisition [Line Items]
Total purchase price consideration and fair value of non-controlling interest	$ 1,560,523
Successor
Business Acquisition [Line Items]
Ownership interest of non-controlling interest	10.40%	7.80%
Successor | Centennial Resource Production, LLC
Business Acquisition [Line Items]
Cash consideration	$ 1,186,744
Repayment of CRP long-term de	189,000
Total purchase price consideration	1,375,744
Fair value of non-controlling interest	184,779
Total purchase price consideration and fair value of non-controlling interest	$ 1,560,523
Ownership interest of non-controlling interest	11.00%

Business Combination - Allocati

Business Combination - Allocation of Purchase Consideration (Details) - Centennial Resource Production, LLC $ in Thousands	Oct. 11, 2016USD ($)
Fair value of assets acquired:
Other current assets	$ 13,341
Derivative instruments	1,052
Proved properties	444,551
Unproved properties	1,138,423
Other property, plant and equipment	1,764
Goodwill	0
Total fair value of assets acquired	1,599,131
Fair value of liabilities assumed:
Accounts payable and accrued expenses	30,156
Other current liabilities	63
Derivative instruments	3,400
Asset retirement obligation	4,989
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	$ 1,560,523

Business Combination - Pro Form

Business Combination - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Centennial Resource Production, LLC
Business Acquisition [Line Items]
Total revenues	$ 98,833	$ 90,460
Total operating expenses	86,490	123,702
Net income (loss) attributable to common shareholders of Centennial Resource Development, Inc.	$ 1,666	$ (6,397)
Basic net loss per share (in dollars per share)	$ 0.01	$ (0.04)
Diluted net loss per share (in dollars per share)	$ 0.01	$ (0.04)
Acquisition-related Costs [Member]
Business Acquisition [Line Items]
Transaction related costs	$ 18,700
Adjustment of Incentive Unit Compensation [Member]
Business Acquisition [Line Items]
Incentive unit compensation	$ 165,400

Property Acquisitions and Dis45

Property Acquisitions and Dispositions - Acquisitions, Narrative (Details) $ in Thousands	Jun. 03, 2016USD ($)	Sep. 03, 2015USD ($)a	Sep. 01, 2015USD ($)	Dec. 31, 2016USD ($)aWells	Jun. 30, 2016USD ($)aWells	May 31, 2016USD ($)a	Jun. 30, 2014USD ($)a	Dec. 31, 2015USD ($)
Successor
Business Acquisition [Line Items]
Payable to Silverback				$ 32,293
Successor | Undeveloped Acreage and Oil and Gas Producing Properties From Silverback Exploration, LLC
Business Acquisition [Line Items]
Consideration				855,000
Proved oil and natural gas properties				116,700
Payable to Silverback				$ 32,300
Number of horizontal wells acquired (in wells) | Wells				31
Gas and oil area, area offset by existing acreage (in acres) | a				35,500
Gas and oil area, acreage subject to consents to assign (in acres) | a				1,250
Gas and oil area, operated by company, percent				90.00%
Gas and oil area, working interest, percent				90.00%
Predecessor
Business Acquisition [Line Items]
Payable to Silverback								$ 0
Predecessor | Unproved And Proved Properties In The Delaware Basin
Business Acquisition [Line Items]
Proved oil and natural gas properties	$ 15,374				$ 15,400
Number of horizontal wells acquired (in wells) | Wells					4
Cash consideration	$ 32,979				$ 33,000
Net acres acquired | a					1,580
Predecessor | Unproved Acreage From Caird DB, LLC
Business Acquisition [Line Items]
Consideration						$ 9,800
Net acres acquired | a						875
Predecessor | Proved and Unproved Oil and Natural gas Properties in Delaware Basin
Business Acquisition [Line Items]
Proved oil and natural gas properties			$ 7,731
Cash consideration			$ 16,006
Predecessor | Non-Operated Interest in Delaware Basin
Business Acquisition [Line Items]
Proved oil and natural gas properties		$ 6,491
Cash consideration		$ 6,369					$ 11,000
Net acres acquired | a		1,804					2,400

Property Acquisitions and Dis46

Property Acquisitions and Dispositions - Purchase Price Allocation (Details) - Predecessor - USD ($) $ in Thousands	Jun. 03, 2016	Sep. 03, 2015	Sep. 01, 2015	Jun. 30, 2016	Jun. 30, 2014
Proved and Unproved Oil and Natural gas Properties in Delaware Basin
Business Acquisition [Line Items]
Cash consideration			$ 16,006
Fair value of assets and liabilities acquired:
Proved oil and natural gas properties			7,731
Unproved oil and natural gas properties			8,312
Total fair value of oil and natural gas properties acquired			16,043
Asset retirement obligation			(37)
Total fair value of net assets acquired			$ 16,006
Non-Operated Interest in Delaware Basin
Business Acquisition [Line Items]
Cash consideration		$ 6,369			$ 11,000
Fair value of assets and liabilities acquired:
Proved oil and natural gas properties		6,491
Unproved oil and natural gas properties		0
Total fair value of oil and natural gas properties acquired		6,491
Asset retirement obligation		(122)
Total fair value of net assets acquired		$ 6,369
Unproved And Proved Properties In The Delaware Basin
Business Acquisition [Line Items]
Cash consideration	$ 32,979			$ 33,000
Fair value of assets and liabilities acquired:
Proved oil and natural gas properties	15,374			$ 15,400
Unproved oil and natural gas properties	18,071
Total fair value of oil and natural gas properties acquired	33,445
Revenue Suspense	(400)
Asset retirement obligation	(66)
Total fair value of net assets acquired	$ 32,979

Property Acquisitions and Dis47

Property Acquisitions and Dispositions - Dispositions, Narrative (Details) - Predecessor $ in Thousands	1 Months Ended			3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2014USD ($)aWells	May 31, 2014USD ($)	Feb. 28, 2014USD ($)	Jun. 30, 2014USD ($)	Oct. 10, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)aWells
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sales of oil and natural gas properties					$ 0	$ 2,691	$ 72,382
Ward County, Texas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net acres | a	1,845						1,845
Number of vertical wells | Wells	18						18
Proceeds from sales of oil and natural gas properties	$ 12,500
Gain (loss) on sale of oil and gas properties	$ 1,500
Caprock Field
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sales of oil and natural gas properties		$ 59,300
Gain (loss) on sale of oil and gas properties				$ 2,200
Atlantic Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sales of oil and natural gas properties			$ 71,800
Gain (loss) on sale of oil and gas properties			$ 20,000
Interest in Atlantic Midstream			98.50%

Accounts Receivable, Accounts48

Accounts Receivable, Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and natural gas	$ 11,596
Joint interest billings	2,942
Hedge settlements	194
Other	2
Allowance for doubtful accounts	0
Accounts receivable, net	$ 14,734
Predecessor
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and natural gas		$ 5,789
Joint interest billings		1,514
Hedge settlements		3,956
Other		1,844
Allowance for doubtful accounts		(91)
Accounts receivable, net		$ 13,012

Accounts Receivable, Accounts49

Accounts Receivable, Accounts Payable and Accrued Expenses Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Predecessor
Entity Information [Line Items]
Accounts payable		$ 1,827
Accrued capital expenditures		11,700
Revenues payable		3,439
Payable to Silverback		0
Accrued underwriting fees		0
Other		3,019
Accounts payable and accrued expenses		$ 19,985
Successor
Entity Information [Line Items]
Accounts payable	$ 11,210
Accrued capital expenditures	24,038
Revenues payable	3,815
Payable to Silverback	32,293
Accrued underwriting fees	7,719
Other	7,025
Accounts payable and accrued expenses	$ 86,100

Long-Term Debt (Details)

Long-Term Debt (Details) - Line of Credit	Dec. 28, 2016USD ($)Redetermination	Oct. 11, 2016USD ($)	Dec. 31, 2016USD ($)	Oct. 10, 2016USD ($)	Oct. 15, 2014USD ($)
Predecessor | Term Loan
Debt Instrument [Line Items]
Commitment amount					$ 65,000,000
Predecessor | Revolving Credit Facility
Debt Instrument [Line Items]
Borrowing base amount				$ 140,000,000
Commitment amount					500,000,000
Line of credit outstanding				124,000,000
Remaining borrowing capacity				15,600,000
Predecessor | Letter of Credit
Debt Instrument [Line Items]
Commitment amount					$ 15,000,000
Letters of credit outstanding				$ 400,000
Successor | Revolving Credit Facility
Debt Instrument [Line Items]
Borrowing base amount	$ 250,000,000	$ 200,000,000
Number of optional borrowing base redeterminations | Redetermination	2
Borrowing base redeterminations, automatic decrease in borrowing capacity unless waived by lenders	25.00%
Basis points added to LIBOR rate to determine base rate	1.00%
Commitment fee on unused amounts	0.50%
Line of credit outstanding			$ 0
Remaining borrowing capacity			249,600,000
Successor | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Debt instrument, covenant, minimum current ratio	1
Successor | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Debt instrument, covenant, maximum leverage ratio, measurement period	12 months
Debt instrument, covenant, maximum leverage ratio	4
Successor | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding			$ 400,000
LIBOR | Successor | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	2.25%	2.25%
LIBOR | Successor | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	3.25%	3.25%
Federal Funds Rate [Member] | Successor | Revolving Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
One-Month London Interbank Offered Rate (LIBOR) [Member] | Successor | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	1.25%
One-Month London Interbank Offered Rate (LIBOR) [Member] | Successor | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	2.25%

Long-Term Debt - Term Loan (Det

Long-Term Debt - Term Loan (Details) - Predecessor - Term Loan - Line of Credit $ in Thousands	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Term loan	$ 65,000
Unamortized deferred financing costs	(351)
Term loan, net of unamortized deferred financing costs	$ 64,649

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	Oct. 10, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Current taxes
Federal		$ 0
State		0
Current taxes		0
Deferred taxes
Federal		0
State		0
Deferred taxes		0
Income tax benefit (expense)		0
Increase in noncontrolling interest due to sale of equity		5,600
Deferred tax valuation allowance		5,148
Predecessor
Current taxes
Federal										$ 0	$ 0	$ 0
State										0	0	0
Current taxes										0	0	0
Deferred taxes
Federal										0	0	0
State										406	572	(1,524)
Deferred taxes										406	572	(1,524)
Income tax benefit (expense)	$ 0		$ 0	$ (406)	$ 0	$ (572)	$ 0	$ 0	$ 0	$ 406	572	$ (1,524)
Deferred tax valuation allowance						$ 0					$ 0
Domestic Tax Authority | Successor
Deferred taxes
Operating loss carryforwards		7,300
Tax Benefit For Issuance Of Shares To Noncontrolling Interest | Successor
Deferred taxes
Deferred tax valuation allowance		$ 2,000

Income Taxes - Effective Income

Income Taxes - Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	Oct. 10, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Income Tax [Line Items]
Income tax (benefit) expense at the federal statutory rate		$ (3,145)
State income taxes - net of federal income tax benefits		0
Excess depletion		0
Noncontrolling interest in partnership		273
Nondeductible expenses		4
Change in valuation allowance		2,868
Income tax benefit (expense)		$ 0
Predecessor
Income Tax [Line Items]
Income tax (benefit) expense at the federal statutory rate										$ 0	$ 0	$ 0
State income taxes - net of federal income tax benefits										406	572	(1,524)
Excess depletion										0	0	0
Noncontrolling interest in partnership										0	0	0
Nondeductible expenses										0	0	0
Change in valuation allowance										0	0	0
Income tax benefit (expense)	$ 0		$ 0	$ (406)	$ 0	$ (572)	$ 0	$ 0	$ 0	$ 406	$ 572	$ (1,524)

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Deferred tax assets:
Net operating loss carryforwards	$ 2,590
Capitalized intangible drilling cost	10,314
Equity-based compensation	467
Other assets	291
Total deferred tax assets	13,662
Investment in Centennial Resource Production, LLC
Investment in Centennial Resource Production, LLC	(8,514)
Other liabilities	0
Total deferred tax liabilities	(8,514)
Valuation allowance	(5,148)
Net deferred tax asset	$ 0
Predecessor
Deferred tax assets:
Net operating loss carryforwards		$ 0
Capitalized intangible drilling cost		0
Equity-based compensation		0
Other assets		0
Total deferred tax assets		0
Investment in Centennial Resource Production, LLC
Investment in Centennial Resource Production, LLC		0
Other liabilities		(2,361)
Total deferred tax liabilities		(2,361)
Valuation allowance		0
Net deferred tax liabilities		$ 2,361

Shareholders' and Owners Equi55

Shareholders' and Owners Equity (Details) - Successor $ / shares in Units, $ in Millions	Dec. 28, 2016USD ($)shares	Oct. 11, 2016USD ($)$ / sharesshares	Dec. 31, 2016dayvotedirector$ / sharesshares
Class of Stock [Line Items]
Capital stock authorized (in shares)			621,000,000
Common stock, shares authorized (in shares)			620,000,000
Preferred stock, shares authorized (in shares)			1,000,000
Common stock, par value (in dollars per share) | $ / shares			$ 0.0001
Conversion of Class B Common Stock to Class A Common Stock
Class of Stock [Line Items]
Stock conversion ratio		1
Private Placement
Class of Stock [Line Items]
Proceeds from issuance of stock | $	$ 889.6
Common Class A
Class of Stock [Line Items]
Common stock, shares authorized (in shares)			600,000,000
Common stock, par value (in dollars per share) | $ / shares		$ 0.0001
Common stock, shares outstanding (in shares)			201,091,646
Common stock, number of votes per share (in votes) | vote			1
Common stock, threshold for election of directors			50.00%
Common Class A | Conversion of Class B Common Stock to Class A Common Stock
Class of Stock [Line Items]
Stock issued upon conversion of stock (in shares)			12,500,000
Common Class A | Conversion of CRP Common Units for Class A Common Stock
Class of Stock [Line Items]
Share issued during conversion of units (in shares)		844,079	50,000,000
Common Class A | Private Placement
Class of Stock [Line Items]
Stock issued during period (in shares)			101,005,000
Proceeds from issuance of stock | $		$ 1,000
Common Class A | Private Placement | Riverstone Centennial Holdings, L.P.
Class of Stock [Line Items]
Stock issued during period (in shares)		81,005,000
Common Class A | Private Placement | Other Accredited Investors
Class of Stock [Line Items]
Stock issued during period (in shares)		20,000,000
Common Class A | Private Placement | Affiliates of Riverstone Investment Group, LLC
Class of Stock [Line Items]
Stock issued during period (in shares)	3,473,590		36,485,970
Common Class A | Private Placement | Other Investors
Class of Stock [Line Items]
Stock issued during period (in shares)	33,012,380
Common Class B | Private Placement
Class of Stock [Line Items]
Common stock, par value (in dollars per share) | $ / shares			$ 0.0001
Common Class C
Class of Stock [Line Items]
Common stock, shares authorized (in shares)			20,000,000
Common stock, par value (in dollars per share) | $ / shares		$ 0.0001
Common stock, shares outstanding (in shares)			19,155,921
Common Class C | Centennial Contributors
Class of Stock [Line Items]
Stock issued during period (in shares)		20,000,000
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares authorized (in shares)			1
Preferred stock, shares outstanding (in shares)			1
Preferred stock, number of directed nominated and elected | director			1
Series A Preferred Stock | Centennial Resource Development
Class of Stock [Line Items]
Preferred stock, shares outstanding (in shares)			1
Preferred stock, liquidation preference per share (in dollars per share) | $ / shares			$ 0.0001
Preferred stock, redemption terms, threshold for CRP common units and/or shares of Class A common shares			5,000,000
Series B Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares authorized (in shares)			104,400
Preferred stock, shares outstanding (in shares)			104,400
Preferred stock, liquidation preference per share (in dollars per share) | $ / shares			$ 0.0001
Preferred stock, redemption price, number of consecutive trading days | day			10
Series B Preferred Stock | Conversion of Series B Preferred Stock to Class A Common Stock
Class of Stock [Line Items]
Perferred stock conversion ratio	250
Series B Preferred Stock | Private Placement | Affiliates of Riverstone Investment Group, LLC
Class of Stock [Line Items]
Stock issued during period (in shares)	104,400
Restricted stock awards | Director And Executive Officer | Common Class A
Class of Stock [Line Items]
Stock issued during period (in shares)			256,597

Shareholders' and Owners Equi56

Shareholders' and Owners Equity - Warrants (Details) - $ / shares	Mar. 01, 2017	Dec. 31, 2016
Subsequent Event
Class of Warrant or Right [Line Items]
Common stock, shares outstanding upon exercise of warrants (in shares)	253,000,000
Public Warrants | Subsequent Event
Class of Warrant or Right [Line Items]
Warrant exercise price (in dollars per share)	$ 0.01
Warrants, cashless exercise, common stock issues as percent of warrants	37.60%
Warrants, number of securities called by warrant (in shares)	6,270,000
Public Warrants | Subsequent Event | Minimum
Class of Warrant or Right [Line Items]
Warrant, cashless exercise, average common stock price per share (in dollars per share)	$ 11.50
Public Warrants | Subsequent Event | Maximum
Class of Warrant or Right [Line Items]
Warrant, cashless exercise, average common stock price per share (in dollars per share)	$ 18.44
Successor | Warrants To Purchase Class A Common Stock, Silver Run
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)		24,666,643
Warrants, number of class A shares per warrant (in shares)		1
Warrant exercise price (in dollars per share)		$ 11.50
Warrant expiration period		5 years
Successor | Warrants To Purchase Class A Common Stock, IPO
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)		16,666,643
Successor | Warrants To Purchase Class A Common Stock, Private Placement
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)		8,000,000

Shareholders' and Owners Equi57

Shareholders' and Owners Equity - Noncontrolling Interest (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 28, 2016	Oct. 11, 2016
Predecessor
Noncontrolling Interest [Line Items]
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Percent		10.90%
Net loss attributable to noncontrolling interest		$ 0	$ 0	$ (2)
Successor
Noncontrolling Interest [Line Items]
Ownership interest of parent					92.20%	89.60%
Ownership interest of non-controlling interest					7.80%	10.40%
Net loss attributable to noncontrolling interest	$ (904)
Centennial Resource Production, LLC | Successor
Noncontrolling Interest [Line Items]
Voting interest acquired						89.10%
Ownership interest of non-controlling interest						11.00%

Shareholders' and Owners Equi58

Shareholders' and Owners Equity - Owners' Equity (Predecessor) (Details) - Predecessor	Oct. 10, 2016USD ($)	Oct. 10, 2016USD ($)	Oct. 10, 2016USD ($)	Dec. 31, 2015USD ($)class	Dec. 31, 2014USD ($)
Class of Stock [Line Items]
Number of classes of membership interests | class				2
Incentive unit compensation			$ 165,394,000	$ 0	$ 0
Deemed contribution from payment of transaction Costs	$ 14,000,000
Members' equity, contributions		$ 179,442,000		$ 111,396,000	$ 59,926,000
Centennial HoldCo
Class of Stock [Line Items]
Ownership interest				61.20%
Members' equity, contributions				$ 27,200,000
Centennial HoldCo | Class A
Class of Stock [Line Items]
Members' equity, contributed capital				289,400,000
Members' equity, remaining capital contribution commitment				$ 32,500,000
Celero
Class of Stock [Line Items]
Ownership interest				21.20%
Celero | Class B
Class of Stock [Line Items]
Members' equity, contributed capital				$ 125,400,000
Members' equity, remaining capital contribution commitment				$ 0
Follow-On
Class of Stock [Line Items]
Ownership interest				17.60%
Members' equity, contributions				$ 84,200,000
Follow-On | Class A
Class of Stock [Line Items]
Members' equity, contributed capital				84,200,000
Members' equity, remaining capital contribution commitment				$ 100,300,000

Equity Based Compensation (Deta

Equity Based Compensation (Details) - Successor $ in Thousands	3 Months Ended
	Dec. 31, 2016USD ($)
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity based compensation expense	$ 1,333
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity based compensation expense	405
Stock option awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity based compensation expense	$ 928

Equity Based Compensation - Res

Equity Based Compensation - Restricted Stock (Details) - Successor - Restricted stock awards $ / shares in Units, $ in Millions	3 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding, beginning of period (in shares) | shares	0
Vested (in shares) | shares	0
Granted (in shares) | shares	256,597
Canceled (in shares) | shares	0
Outstanding, end of period (in shares) | shares	256,597
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Outstanding, beginning of period (in dollars per share) | $ / shares	$ 0
Vested (in dollars per share) | $ / shares	0
Granted (in dollars per share) | $ / shares	20.03
Canceled (in dollar per share) | $ / shares	0
Outstanding, end of period (in dollars per share) | $ / shares	$ 20.03
Unrecognized compensation costs | $	$ 4.7
Unrecognized compensation costs, period for recognition	2 years 6 months 22 days

Equity Based Compensation - Nar

Equity Based Compensation - Narrative (Details) - USD ($) $ in Thousands	Oct. 11, 2016	Oct. 07, 2016	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity based compensation expense			$ 0
Successor | 2016 Long Term Incentive Plan | Common Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance under LTIP (in shares)		16,500,000
Successor | 2016 Long Term Incentive Plan | Stock option awards | Common Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option expiration period		10 years
Vesting period		3 years
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity based compensation expense				$ 165,394	$ 0	$ 0
Predecessor | Incentive Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	5 years

Equity Based Compensation - Ass

Equity Based Compensation - Assumptions Used in Granting Stock Options (Details) - Successor - Stock option awards $ / shares in Units, $ in Thousands	3 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares) | shares	2,760,500
Weighted average grant date fair value (in dollars per share)	$ 5.93
Weighted average exercise price (in dollars per share)	$ 14.67
Total fair value (in thousands) | $	$ 16,375
Expected term	6 years
Expected stock volatility	40.00%
Dividend yield	0.00%
Risk-free interest rate	1.50%

Equity Based Compensation - Opt

Equity Based Compensation - Option Activity (Details) - Successor $ / shares in Units, $ in Thousands	3 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Nonvested Options, Weighted Average Exercise Price
Unrecognized compensation costs | $	$ 15,300
Stock option awards
Options
Outstanding, beginning of period (in shares) | shares	0
Exercised (in shares) | shares	0
Granted (in shares) | shares	2,760,500
Forfeited (in shares) | shares	(25,000)
Outstanding, end of period (in shares) | shares	2,735,500
Weighted Average Exercise Price
Outstanding, beginning of period (In dollars per share)	$ 0
Exercised (in dollars per share)	0
Granted (in dollars per share)	14.67
Forfeited (in dollars per share)	14.52
Outstanding, end of period (In dollars per share)	$ 14.67
Granted, weighted average remaining term (in years)	5 years 9 months 18 days
Granted, aggregate intrinsic value | $	$ 13,934
Forfeited, weighted average remaining term (in years)	5 years 9 months 18 days
Forfeited, aggregate intrinsic value | $	$ 130
Outstanding, weighted average remaining term (in years)	5 years 9 months 18 days
Outstanding, aggregate intrinsic value | $	$ 13,804
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Exercisable (in shares) | shares	0
Exercisable (in dollars per share)	$ 0
Exercisable, weighted average remaining term (in years)	0 years
Exercisable, aggregate intrinsic value | $	$ 0
Nonvested Options
Non-vested, beginning of period (in shares) | shares	0
Vested (in shares) | shares	0
Forfeited (in shares) | shares	(25,000)
Non-vested, end of period (in shares) | shares	2,735,500
Nonvested Options, Weighted Average Grant Date Fair Value
Non-vested, beginning of period (in dollars per share)	$ 0
Vested (in dollars per share)	0
Granted (in dollars per share)	5.93
Forfeited (in dollars per share)	5.86
Non-vested, end of period (in dollars per share)	5.93
Nonvested Options, Weighted Average Exercise Price
Non-vested, beginning of period (in dollar per share)	0
Vested (in dollars per share)	0
Granted (in dollars per share)	14.67
Forfeited (in dollars per share)	14.52
Non-vested, end of period (in dollars per share)	$ 14.67
Unrecognized compensation costs, period for recognition	2 years 9 months 29 days

Derivative Instruments (Details

Derivative Instruments (Details) - Successor - Not Designated as Hedging Instrument	12 Months Ended
	Dec. 31, 2016$ / bblbbl
Crude Oil Swap - Oil 2017
Derivative [Line Items]
Derivative notional amount (in bbl) | bbl	675,250
Derivative weighted average floor price (in $ per bbl) | $ / bbl	50.41
Crude Oil Swap - Oil 2018
Derivative [Line Items]
Derivative notional amount (in bbl) | bbl	36,500
Derivative weighted average floor price (in $ per bbl) | $ / bbl	55.95
Crude Oil Basis Swap - Oil 2017
Derivative [Line Items]
Derivative notional amount (in bbl) | bbl	127,750
Derivative weighted average floor price (in $ per bbl) | $ / bbl	(0.20)
Crude Oil Basis Swap - Oil 2018
Derivative [Line Items]
Derivative notional amount (in bbl) | bbl	0
Derivative weighted average floor price (in $ per bbl) | $ / bbl	0
Natural Gas Swap - 2017
Derivative [Line Items]
Derivative notional amount (in bbl) | bbl	1,460,000
Derivative weighted average floor price (in $ per bbl) | $ / bbl	2.94
Natural Gas Swap - 2018
Derivative [Line Items]
Derivative notional amount (in bbl) | bbl	0
Derivative weighted average floor price (in $ per bbl) | $ / bbl	0

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Successor
Derivative [Line Items]
Derivative asset, net	$ (5)
Predecessor
Derivative [Line Items]
Derivative asset, net		$ 21.1

Derivative Instruments - Fair V

Derivative Instruments - Fair Value of Derivative Instruments Balance Sheet Classification (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts	$ 739
Netting Adjustments	(308)
Net Amounts Presented on the Consolidated Balance Sheets	431
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts	5,689
Netting Adjustments	(308)
Net Amounts Presented on the Consolidated Balance Sheets	5,381
Successor | Current assets
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts	739
Netting Adjustments	(308)
Net Amounts Presented on the Consolidated Balance Sheets	431
Successor | Noncurrent assets
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts	0
Netting Adjustments	0
Net Amounts Presented on the Consolidated Balance Sheets	0
Successor | Current liabilities
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts	5,669
Netting Adjustments	(308)
Net Amounts Presented on the Consolidated Balance Sheets	5,361
Successor | Noncurrent Liabilities
Derivative Liability, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts	20
Netting Adjustments	0
Net Amounts Presented on the Consolidated Balance Sheets	$ 20
Predecessor
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts		$ 21,540
Netting Adjustments		(427)
Net Amounts Presented on the Consolidated Balance Sheets		21,113
Predecessor | Current assets
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts		19,469
Netting Adjustments		(426)
Net Amounts Presented on the Consolidated Balance Sheets		19,043
Predecessor | Noncurrent assets
Derivative Asset, Fair Value, Amount Not Offset Against Collateral [Abstract]
Gross Amounts		2,071
Netting Adjustments		(1)
Net Amounts Presented on the Consolidated Balance Sheets		$ 2,070

Derivative Instruments - Gain (

Derivative Instruments - Gain (Loss) On Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ (1,548)
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments		$ (6,838)	$ 20,756	$ 41,943

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Measurements, Recurring - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Successor | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, net	$ 0
Successor | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, net	4,950,000
Successor | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, net	$ 0
Predecessor | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, net		$ 0
Predecessor | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, net		21,113,000
Predecessor | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, net		$ 0

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 4,989
Liabilities incurred	187
Liabilities acquired	2,002
Liabilities settled	(1)
Accretion expense	49
Revision of estimated liabilities	0
Asset retirement obligations, end of period	7,226	$ 4,989
Predecessor
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 2,652	2,288	$ 1,824
Liabilities incurred		174	133
Liabilities acquired		66	178
Liabilities settled		(42)	0
Accretion expense		134	139	$ 156
Revision of estimated liabilities		32	14
Asset retirement obligations, end of period		$ 2,652	$ 2,288	$ 1,824

Transactions With Related Par70

Transactions With Related Parties - Founder Shares (Details) $ / shares in Units, $ in Thousands	Oct. 11, 2016USD ($)day$ / shares	Apr. 08, 2016shares	Feb. 24, 2016$ / sharesshares	Nov. 06, 2015USD ($)$ / sharesshares	Dec. 31, 2016USD ($)shares
Successor | Common Class A
Related Party Transaction [Line Items]
Stock issued during period | $	$ 1,010,050				$ 530,507
Common stock, shares outstanding (in shares)					201,091,646
Successor | Initial Stockholders | Common Class A | Affiliated Entity
Related Party Transaction [Line Items]
Limitation on sale of class A common stock, sale price threshold (in dollars per share) | $ / shares	$ 12
Limitation on sale of class A common stock, sale price threshold, number of trading days | day	20
Limitation on sale of class A common stock, sale price threshold, trading period | day	30
Limitation on sale of class A common stock, sale price threshold, period after business combination	150 days
Silver Run | Common Class B
Related Party Transaction [Line Items]
Stock dividend (in dollars per share) | $ / shares			$ 0.125
Silver Run | Company Sponsors | Common Class B | Affiliated Entity
Related Party Transaction [Line Items]
Stock issued during period (in shares)				11,500,000
Stock issued during period | $				$ 25
Share price (in dollars per share) | $ / shares				$ 0.002
Stock forfeited in period (in shares)		437,500
Silver Run | Company Sponsors | Common Class B | Affiliated Entity | Transfer Of Shares From Sponsors To Directors
Related Party Transaction [Line Items]
Stock transferred per director (in shares)				40,000
Silver Run | Initial Stockholders | Affiliated Entity
Related Party Transaction [Line Items]
Ownership percentage		20.00%
Silver Run | Initial Stockholders | Common Class B | Affiliated Entity
Related Party Transaction [Line Items]
Common stock, shares outstanding (in shares)		12,500,000	12,937,000
Silver Run | Initial Stockholders | Common Class A | Affiliated Entity
Related Party Transaction [Line Items]
Limitation on sale of class A common stock, period after business combination	1 year
Limitation on sale of class A common stock, sale price threshold (in dollars per share) | $ / shares	$ 12
Limitation on sale of class A common stock, sale price threshold, number of trading days | day	20
Limitation on sale of class A common stock, sale price threshold, trading period | day	30
Limitation on sale of class A common stock, sale price threshold, period after business combination	150 days
Silver Run | Conversion of Founder Shares To Class A Common Stock | Common Class A
Related Party Transaction [Line Items]
Stock conversion ratio	1

Transactions With Related Par71

Transactions With Related Parties (Details)

Dec. 28, 2016shares

Nov. 27, 2016USD ($)shares

Oct. 11, 2016USD ($)day$ / sharesshares

Aug. 02, 2016USD ($)

Feb. 29, 2016USD ($)$ / sharesshares

Nov. 10, 2015USD ($)

May 31, 2016USD ($)

Feb. 29, 2016USD ($)$ / sharesshares

Dec. 31, 2016USD ($)$ / sharesshares

Oct. 10, 2016USD ($)

Sep. 30, 2016USD ($)

Dec. 31, 2016USD ($)$ / sharesshares

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Feb. 23, 2016USD ($)

Nov. 06, 2015USD ($)

Predecessor

Related Party Transaction [Line Items]

Administrative support agreement, monthly amount

$ 10,000

Administrative support agreement, expense amount

$ 70,000

Proceeds from term loan

$ 0

$ 0

$ 65,000,000

Issuance of Class A common shares

0

0

0

Acquisition of oil and natural gas properties

55,564,000

43,223,000

22,167,000

Exploration

0

84,000

0

Predecessor | Caird DB, LLC | Affiliated Entity

Related Party Transaction [Line Items]

Acquisition of oil and natural gas properties

$ 9,800,000

Predecessor | Cretic Energy Services, LLC | Affiliated Entity | Drilling and Completion Activities

Related Party Transaction [Line Items]

Expenses to related party

$ 500,000

Predecessor | PennTex Permian, LLC | Affiliated Entity | Gas Gathering Agreement

Related Party Transaction [Line Items]

Term of gas gathering agreement

15 years

Term of extension option for gas gathering agreement

1 year

Net revenue from gas gathering agreement

$ 1,000,000

$ 1,200,000

$ 2,200,000

Predecessor | RockPile Energy Services, LLC | Affiliated Entity | Drilling and Completion Activities

Related Party Transaction [Line Items]

Expenses to related party

$ 3,300,000

Successor

Related Party Transaction [Line Items]

Proceeds from term loan

$ 0

Common stock, par value (in dollars per share) | $ / shares

$ 0.0001

$ 0.0001

Issuance of Class A common shares

$ 1,540,556,000

Acquisition of oil and natural gas properties

849,642,000

Exploration

844,000

Successor | Cretic Energy Services, LLC | Affiliated Entity

Related Party Transaction [Line Items]

Accounts Payable, Related Parties

200,000

$ 200,000

Successor | PennTex Permian, LLC | Affiliated Entity | Gas Gathering Agreement

Related Party Transaction [Line Items]

Net revenue from gas gathering agreement

200,000

Successor | Liberty Oilfield Services, LLC | Affiliated Entity

Related Party Transaction [Line Items]

Expenses to related party

8,200,000

Accounts Payable, Related Parties

3,100,000

3,100,000

Successor | Permian Tank And Manufacturing, Inc | Affiliated Entity

Related Party Transaction [Line Items]

Expenses to related party

1,400,000

Accounts Payable, Related Parties

400,000

400,000

Successor | Oil States Energy Services, LLC | Affiliated Entity

Related Party Transaction [Line Items]

Expenses to related party

1,200,000

Accounts Payable, Related Parties

$ 200,000

$ 200,000

Warrants To Purchase Class A Common Stock | Successor

Related Party Transaction [Line Items]

Warrants issued (in shares) | shares

24,666,643

24,666,643

Warrants, number of class A shares per warrant (in shares) | shares

1

1

Warrant exercise price (in dollars per share) | $ / shares

$ 11.50

$ 11.50

Common Class A | Successor

Related Party Transaction [Line Items]

Common stock, par value (in dollars per share) | $ / shares

$ 0.0001

Common Class A | Successor | Initial Stockholders | Affiliated Entity

Related Party Transaction [Line Items]

Limitation on sale of class A common stock, sale price threshold (in dollars per share) | $ / shares

$ 12

Limitation on sale of class A common stock, sale price threshold, number of trading days | day

20

Limitation on sale of class A common stock, sale price threshold, trading period | day

30

Limitation on sale of class A common stock, sale price threshold, period after business combination

150 days

Capital Units | Successor

Related Party Transaction [Line Items]

Shares converted (in shares) | shares

844,079

Common Class C | Successor

Related Party Transaction [Line Items]

Common stock, par value (in dollars per share) | $ / shares

$ 0.0001

Stock canceled during period (in shares) | shares

844,079

Conversion of CRP Common Units for Class A Common Stock | Common Class A | Successor

Related Party Transaction [Line Items]

Share issued during conversion of units (in shares) | shares

844,079

50,000,000

Conversion of CRP Common Units for Class A Common Stock | Capital Units | Successor

Related Party Transaction [Line Items]

Stock conversion ratio

1

Private Placement | Common Class A | Successor

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

101,005,000

Private Placement | Common Class A | Successor | Riverstone Centennial Holdings, L.P.

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

81,005,000

Private Placement | Common Class A | Successor | Affiliates of Riverstone Investment Group, LLC

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

3,473,590

36,485,970

Private Placement | Series B Preferred Stock | Successor | Affiliates of Riverstone Investment Group, LLC

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

104,400

Stock Subscription Agreement | Successor | Affiliated Entity

Related Party Transaction [Line Items]

Stock subscription agreement, period to register

75 days

Stock Subscription Agreement | Successor | Riverstone Purchasers | Affiliated Entity

Related Party Transaction [Line Items]

Issuance of Class A common shares

$ 430,000,000

Stock Subscription Agreement | Common Class A | Successor | Investors | Affiliated Entity

Related Party Transaction [Line Items]

Gross proceeds threshold for stock subscription to demand offering

$ 50,000,000

Stock issued during period (in shares) | shares

20,000,000

Issuance of Class A common shares

$ 200,000,000

Stock Subscription Agreement | Common Class A | Successor | Riverstone Centennial Holdings, L.P. | Affiliated Entity

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

81,005,000

Issuance of Class A common shares

$ 810,000,000

Stock Subscription Agreement | Common Class A | Successor | Riverstone Purchasers | Affiliated Entity

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

3,473,590

Stock Subscription Agreement | Common Class A | Successor | Other Selling Stockholders | Affiliated Entity

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

33,012,380

Issuance of Class A common shares

$ 480,000,000

Stock Subscription Agreement | Series B Preferred Stock | Successor | Riverstone Purchasers | Affiliated Entity

Related Party Transaction [Line Items]

Stock issued during period (in shares) | shares

104,400

Silver Run | Company Sponsors | Affiliated Entity | Loan Agreement To Cover Expenses Related To IPO

Related Party Transaction [Line Items]

Commitment amount

$ 300,000

Proceeds from term loan

$ 300,000

$ 150,000

$ 150,000

Repayments of related party note

$ 300,000

$ 300,000

Silver Run | Warrants To Purchase Class A Common Stock | Company Sponsors | Affiliated Entity

Related Party Transaction [Line Items]

Warrants issued (in shares) | shares

8,000,000

8,000,000

Warrants issued, price per warrant (in dollars per share) | $ / shares

$ 1.5

Warrants issued

$ 12,000,000

$ 12,000,000

Warrants, number of class A shares per warrant (in shares) | shares

1

1

Warrant exercise price (in dollars per share) | $ / shares

$ 11.5

$ 11.5

Silver Run | Common Class A | Initial Stockholders | Affiliated Entity

Related Party Transaction [Line Items]

Limitation on sale of class A common stock, sale price threshold (in dollars per share) | $ / shares

$ 12

Limitation on sale of class A common stock, sale price threshold, number of trading days | day

20

Limitation on sale of class A common stock, sale price threshold, trading period | day

30

Limitation on sale of class A common stock, sale price threshold, period after business combination

150 days

Commitments and Contingencies -

Commitments and Contingencies - Future Minimum Lease Payments (Details) - Successor $ in Thousands	Dec. 31, 2016USD ($)
Operating Lease, Future Minimum Payments Due [Line Items]
2,017	$ 8,147
2,018	814
2,019	573
2,020	134
2,021	79
Thereafter	7,226
Total	$ 16,973

Commitments and Contingencies73

Commitments and Contingencies (Details) a in Thousands	1 Months Ended			3 Months Ended	9 Months Ended	12 Months Ended
	Jul. 31, 2016	Dec. 31, 2015USD ($)aextension_option	Oct. 31, 2014USD ($)	Dec. 31, 2016USD ($)	Oct. 10, 2016USD ($)	Dec. 31, 2016drilling_rig	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Related Party Transaction [Line Items]
Number of drilling rigs under contract | drilling_rig						4
Predecessor
Related Party Transaction [Line Items]
Contract termination and rig stacking					$ 0		$ (2,387,000)	$ 0
Rent expense					400,000		400,000	$ 500,000
Predecessor | Purchase Agreement
Related Party Transaction [Line Items]
Purchase agreement, term of agreement	9 months
Purchase agreement, term of automatic extensions	30 days
Purchase commitment, termination notice period	30 days
Predecessor | Transportation And Gathering Services Agreement
Related Party Transaction [Line Items]
Transportation and gathering agreement, term of agreement		12 years
Transportation and gathering agreement, number of extension options | extension_option		2
Transportation and gathering agreement, term of extension options		2 years
Transportation and gathering agreement, term of automatic extensions		1 year
Transportation and gathering agreement, termination notice period		60 days
Successor
Related Party Transaction [Line Items]
Contract termination and rig stacking				$ 0
Rent expense				100,000
Gas Gathering Agreement | PennTex Permian, LLC | Affiliated Entity | Predecessor
Related Party Transaction [Line Items]
Minimum fee due per day			$ 7,000
Expenses to related party					$ 2,100,000		1,700,000
Gas Gathering Agreement | PennTex Permian, LLC | Affiliated Entity | Predecessor | Transportation And Gathering Services Agreement
Related Party Transaction [Line Items]
Transportation and gathering agreement, number of acres | a		28
Gas Gathering Agreement | PennTex Permian, LLC | Affiliated Entity | Successor
Related Party Transaction [Line Items]
Remaining liability related to gas gathering agreement		$ 2,100,000					$ 2,100,000
Expenses to related party				$ 100,000

Supplemental Information Abou74

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) - Costs Incurred For Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Acquisition costs:
Proved properties	$ 561,251
Unproved properties	1,905,660
Development costs	44,602
Exploration costs	844
Total	$ 2,512,357
Predecessor
Acquisition costs:
Proved properties		$ 16,386	$ 14,268	$ 5,758
Unproved properties		39,399	28,955	16,409
Development costs		53,512	87,452	324,802
Exploration costs		0	84	0
Total		$ 109,297	$ 130,759	$ 346,969

Supplemental Information Abou75

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) - Results of Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Oil, natural gas and NGL sales	$ 29,717
Costs:
Lease operating expenses	3,541
Severance and ad valorem taxes	1,636
Transportation, processing, gathering and other operating expenses	2,187
Depletion, amortization and accretion of asset retirement obligations	14,486
Abandonment expense and impairment of unproved properties	0
Exploration	844
Contract termination and rig stacking	0
Income tax expense (benefit)	0
Results of operations	$ 7,023
Predecessor
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Oil, natural gas and NGL sales		$ 69,116	$ 90,460	$ 131,825
Costs:
Lease operating expenses		11,036	21,173	17,690
Severance and ad valorem taxes		3,696	5,021	6,875
Transportation, processing, gathering and other operating expenses		4,583	5,732	4,772
Depletion, amortization and accretion of asset retirement obligations		62,228	89,350	68,981
Abandonment expense and impairment of unproved properties		2,545	7,619	20,025
Exploration		0	84	0
Contract termination and rig stacking		0	2,387	0
Income tax expense (benefit)		(406)	(572)	1,524
Results of operations		$ (14,566)	$ (40,334)	$ 11,958

Supplemental Information Abou76

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) - Calculation of Standardized Measure of Discounted Future Net Cash Flows (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016$ / bbl$ / Mcf	Oct. 10, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf
Successor | Crude Oil (MBbls)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Sales Prices	38.49
Successor | Natural Gas (MMcf)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Sales Prices | $ / Mcf	0.98
Successor | Natural Gas Liquids (MBbls)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Sales Prices	14.59
Predecessor | Crude Oil (MBbls)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Sales Prices		36.98	41.85	84.94
Predecessor | Natural Gas (MMcf)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Sales Prices | $ / Mcf		1.24	1.71	4.70
Predecessor | Natural Gas Liquids (MBbls)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Sales Prices		13.28	13.94	22.70

Supplemental Information Abou77

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) - Summary of Changes in Estimated Proved Reserves (Details) MMcf in Thousands, MBbls in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016MMcfMBbls	Oct. 10, 2016MMcfMBbls	Dec. 31, 2015MMcfMBbls	Dec. 31, 2014MMcfMBbls	Dec. 31, 2013MMcfMBbls
Successor | Crude Oil (MBbls)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of period	30,091
Extensions and discoveries	7,063
Revisions of previous estimates	184
Purchases of reserves in place	9,651
Divestitures of reserves in place	0
Production	(523)
End of period	46,466	30,091
Proved developed reserves:	14,551	11,346
Proved undeveloped reserves:	31,914	18,745
Successor | Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of period | MMcf	36,801
Extensions and discoveries | MMcf	12,219
Revisions of previous estimates | MMcf	16,445
Purchases of reserves in place | MMcf	83,992
Divestitures of reserves in place | MMcf	0
Production | MMcf	(1,113)
End of period | MMcf	148,344	36,801
Proved developed reserves: | MMcf	42,190	14,973
Proved undeveloped reserves: | MMcf	106,154	21,828
Successor | Natural Gas Liquids (MBbls)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of period	4,506
Extensions and discoveries	1,225
Revisions of previous estimates	983
Purchases of reserves in place	5,152
Divestitures of reserves in place	0
Production	(96)
End of period	11,770	4,506
Proved developed reserves:	3,618	1,927
Proved undeveloped reserves:	8,152	2,579
Predecessor | Crude Oil (MBbls)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of period	30,091	23,199	19,850	18,510
Extensions and discoveries		5,851	9,444	16,122
Revisions of previous estimates		1,025	(5,109)	56
Purchases of reserves in place		1,600	844	162
Divestitures of reserves in place		0	0	(13,572)
Production		(1,584)	(1,830)	(1,428)
End of period		30,091	23,199	19,850
Proved developed reserves:		11,346	9,347	8,026	6,021
Proved undeveloped reserves:		18,745	13,852	11,823	12,489
Predecessor | Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of period | MMcf	36,801	32,442	27,414	6,968
Extensions and discoveries | MMcf		6,410	11,927	22,575
Revisions of previous estimates | MMcf		(1,521)	(5,204)	178
Purchases of reserves in place | MMcf		2,130	1,363	192
Divestitures of reserves in place | MMcf		0	0	(387)
Production | MMcf		(2,660)	(3,058)	(2,112)
End of period | MMcf		36,801	32,442	27,414
Proved developed reserves: | MMcf		14,973	12,711	11,959	4,837
Proved undeveloped reserves: | MMcf		21,828	19,731	15,455	2,131
Predecessor | Natural Gas Liquids (MBbls)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of period	4,506	3,851	1,551	525
Extensions and discoveries		773	1,432	1,127
Revisions of previous estimates		(110)	995	180
Purchases of reserves in place		245	204	23
Divestitures of reserves in place		0	0	(69)
Production		(253)	(331)	(235)
End of period		4,506	3,851	1,551
Proved developed reserves:		1,927	1,603	766	382
Proved undeveloped reserves:		2,579	2,248	785	143

Supplemental Information Abou78

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) - Narrative (Details) - Oil, Natural Gas, and Natural Gas Liquids - MBoe MBoe in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Reserve Quantities [Line Items]
Proved reserves, net period increase (decrease), percent			104.00%
Proved reserves	82,959	40,730	82,959
Purchases of reserves in place	28,801
Extensions	10,324
Improved results	3,908
Production	805
Predecessor
Reserve Quantities [Line Items]
Proved reserves, net period increase (decrease), percent		25.00%		25.00%
Proved reserves				32,457	25,970
Purchases of reserves in place		2,200		1,275
Extensions		7,692		12,864	21,012
Production		2,280
Revisions of previous estimates		660		(4,981)	265
Revisions of previous estimates, increase (decrease) in commodity prices				(6,794)
Divestitures of reserves in place					13,706

Supplemental Information Abou79

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Cash Flow (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows	$ 2,105,585
Future development costs	(482,162)
Future production costs	(640,306)
Future income tax expenses	(136,587)
Future net cash flows	846,530
10% discount to reflect timing of cash flows	(471,438)
Standardized measure of discounted future net cash flows	$ 375,092	$ 209,713
Predecessor
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows		1,217,641	$ 1,079,962	$ 1,850,205
Future development costs		(297,559)	(277,837)	(440,366)
Future production costs		(413,410)	(450,058)	(457,236)
Future income tax expenses		(5,614)	(6,643)	(10,834)
Future net cash flows		501,058	345,424	941,769
10% discount to reflect timing of cash flows		(291,345)	(210,355)	(575,886)
Standardized measure of discounted future net cash flows		$ 209,713	$ 135,069	$ 365,883	$ 371,307

Supplemental Information Abou80

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) - Principal Source of Change in Standardized Measure of Discounted Cash Flow (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Changes in Standardized Measure of Discounted Future Net Cash Flows [Line Items]
Standardized measure of discounted future net cash flows, beginning of period	$ 209,713
Sales of oil, natural gas and NGLs, net of production costs	(22,354)
Purchase of minerals in place	127,842
Divestiture of minerals in place	0
Extensions and discoveries, net of future development costs	55,825
Change in estimated development costs	10,891
Net change in prices and production costs	(978)
Change in estimated future development costs	571
Revisions of previous quantity estimates	20,190
Accretion of discount	4,753
Net change in income taxes	(47,990)
Net change in timing of production and other	16,629
Standardized measure of discounted future net cash flows, end of period	375,092	$ 209,713
Predecessor
Changes in Standardized Measure of Discounted Future Net Cash Flows [Line Items]
Standardized measure of discounted future net cash flows, beginning of period	$ 209,713	135,069	$ 365,883	$ 371,307
Sales of oil, natural gas and NGLs, net of production costs		(49,801)	(58,534)	(102,488)
Purchase of minerals in place		10,145	14,416	5,650
Divestiture of minerals in place		0	0	(242,344)
Extensions and discoveries, net of future development costs		46,438	57,894	312,532
Change in estimated development costs		11,743	16,100	10,386
Net change in prices and production costs		6,661	(494,734)	(3,027)
Change in estimated future development costs		28,998	247,642	2,935
Revisions of previous quantity estimates		3,673	(51,342)	924
Accretion of discount		11,319	37,517	13,561
Net change in income taxes		(1,568)	1,601	(2,762)
Net change in timing of production and other		7,036	(1,374)	(791)
Standardized measure of discounted future net cash flows, end of period		$ 209,713	$ 135,069	$ 365,883

Selected Quarterly Financial 81

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 10, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 10, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Quarterly Financial Information [Line Items]
Revenues		$ 29,717
Operating expenses		36,800
Gain (loss) on sale of oil and natural gas properties		24
Total operating loss		(7,059)
Other income (expense)		(1,926)
Income tax expense (benefit)		0
Net (loss) income attributable to Centennial Resource Development, Inc.		$ (8,081)
Loss per share, basic (in dollars per share)		$ (0.05)
Income (loss) per share, diluted (in dollars per share)		$ (0.05)
Predecessor
Quarterly Financial Information [Line Items]
Revenues	$ 3,327		$ 27,321	$ 23,347	$ 15,121	$ 21,720	$ 21,893	$ 22,431	$ 24,416	$ 69,116	$ 90,460	$ 131,825
Operating expenses	183,465		32,228	30,251	29,855	42,024	30,442	37,184	36,656	275,799	146,306	150,166
Gain (loss) on sale of oil and natural gas properties	0		15	0	(4)	(249)	9	4	2,675	11	2,439	(2,096)
Total operating loss	(180,138)		(4,892)	(6,904)	(14,738)	(20,553)	(8,540)	(14,749)	(9,565)	(206,672)	(53,407)	(20,437)
Other income (expense)	(2,858)		(242)	(9,635)	277	6,938	11,866	(7,922)	3,628	(12,458)	14,510	39,749
Income tax expense (benefit)	0		0	406	0	572	0	0	0	(406)	(572)	1,524
Net (loss) income attributable to Centennial Resource Development, Inc.	$ (182,996)		$ (5,134)	$ (16,133)	$ (14,461)	$ (13,043)	$ 3,326	$ (22,671)	$ (5,937)	$ (218,724)	$ (38,325)	$ 17,790

Uncategorized Items - cdev-2016

Label	Element	Value
Noncontrolling Interest [Member] | Predecessor [Member]
Members' Equity, Contributions	cdev_MembersEquityContributions	$ 0
Parent [Member] | Predecessor [Member]
Members' Equity, Contributions	cdev_MembersEquityContributions	$ 179,442,000