Jagged Peak Energy 10-K23 Mar 182017 FY Annual reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2017	Mar. 09, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Document Fiscal Year Focus	2,017
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Period Focus	FY
Entity Registrant Name	Jagged Peak Energy Inc.
Entity Central Index Key	1,685,715
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		213,126,310
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 621,362,774

CONSOLIDATED AND COMBINED BALAN

CONSOLIDATED AND COMBINED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 9,523	$ 11,727
Accounts receivable	50,734	10,327
Other current assets	806	3,412
Total current assets	61,063	25,466
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method	1,195,831	531,121
Accumulated depletion	(166,592)	(57,529)
Total oil and gas properties, net	1,029,239	473,592
Other property and equipment, net	9,708	3,001
Total property and equipment, net	1,038,947	476,593
OTHER NONCURRENT ASSETS
Unamortized debt issuance costs	3,273	1,503
Derivative instruments	26	0
Other assets	119	14,830
Total noncurrent assets	3,418	16,333
TOTAL ASSETS	1,103,428	518,392
CURRENT LIABILITIES
Accounts payable	382	7,629
Accrued liabilities	132,311	39,225
Derivative instruments	41,782	9,567
Total current liabilities	174,475	56,421
LONG-TERM LIABILITIES
Senior secured revolving credit facility	155,000	132,000
Derivative instruments	11,095	3,287
Asset retirement obligations	811	448
Deferred income taxes	57,943	0
Other long-term liabilities	4,759	124
Total long-term liabilities	229,608	135,859
Commitments and contingencies
STOCKHOLDERS’ / MEMBERS’ EQUITY
Members' equity	0	346,098
Preferred stock, $0.01 par value, 50,000,000 shares authorized, no shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016	0
Common stock, $0.01 par value; 1,000,000,000 shares authorized, 212,930,655 shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016	2,129	0
Additional paid-in capital	773,674
Accumulated deficit	(76,458)	(19,986)
Total stockholders' / members' equity	699,345	326,112
TOTAL LIABILITIES AND STOCKHOLDERS’ / MEMBERS’ EQUITY	$ 1,103,428	$ 518,392

CONSOLIDATED AND COMBINED STATE

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES
Oil sales	$ 241,788	$ 70,078	$ 31,534
Natural gas sales	9,065	2,213	948
NGL sales	15,571	3,068	1,329
Other operating revenues	888	1,163	40
Total revenues	267,312	76,522	33,851
OPERATING EXPENSES
Lease operating expenses	17,874	7,505	3,165
Gathering and transportation expenses	4,424	1,046	171
Production and ad valorem taxes	16,120	4,345	2,244
Exploration	31	2,484	11
Depletion, depreciation, amortization and accretion	111,049	40,417	22,685
Impairment of unproved oil and natural gas properties	373	372	6,489
General and administrative expenses (including equity-based compensation of $442,976, $0 and $0 in 2017, 2016 and 2015, respectively)	466,067	11,690	7,446
Other operating expenses	247	649	250
Total operating expenses	616,185	68,508	42,461
INCOME (LOSS) FROM OPERATIONS	(348,873)	8,014	(8,610)
OTHER INCOME (EXPENSE)
Gain (loss) on commodity derivatives	(42,615)	(15,145)	1,323
Interest expense, net	(2,861)	(2,629)	(197)
Other, net	358	0	0
Total other income (expense)	(45,118)	(17,774)	1,126
INCOME (LOSS) BEFORE INCOME TAX	(393,991)	(9,760)	(7,484)
Income tax expense (benefit)	57,943	0	0
NET INCOME (LOSS)	$ (451,934)	(9,760)	(7,484)
Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share:
Basic (in dollars per share)	$ (0.36)
Diluted (in dollars per share)	$ (0.36)
Weighted-average common shares outstanding:
Basic (in shares)	212,932
Diluted (in shares)	212,932
Predecessor
OTHER INCOME (EXPENSE)
NET INCOME (LOSS)	$ (375,476)	(9,760)	(7,484)
Successor
OTHER INCOME (EXPENSE)
NET INCOME (LOSS)	$ (76,458)	$ 0	$ 0

CONSOLIDATED AND COMBINED BALA4

CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred stock par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock shares authorized (in shares)	50,000,000	0
Preferred stock shares issued (in shares)	0	0
Common stock par value (in dollars per share)	$ 0.01	$ 0.01
Common stock shares authorized (in shares)	1,000,000,000	0
Common stock shares issued (in shares)	212,930,655	0

CONSOLIDATED AND COMBINED STAT5

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Equity-based compensation	$ 442,976	$ 0	$ 0

CONSOLIDATED AND COMBINED STAT6

CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Members' Equity	Common Stock	Additional Paid-in Capital	Accumulated Deficit
Beginning Balance (Predecessor) at Dec. 31, 2014	$ 240,814	$ 243,556			$ (2,742)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Capital contributions \| Predecessor	51,000	51,000
Net income (loss) \| Predecessor	(7,484)				(7,484)
Net income (loss)	(7,484)
Ending Balance (Predecessor) at Dec. 31, 2015	284,330	294,556			(10,226)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Capital contributions \| Predecessor	51,542	51,542
Net income (loss) \| Predecessor	(9,760)				(9,760)
Net income (loss)	(9,760)
Ending Balance (Predecessor) at Dec. 31, 2016	326,112	346,098	$ 0	$ 0	(19,986)
Ending Balance at Dec. 31, 2016	326,112
Ending Balance (in shares) (Predecessor) at Dec. 31, 2016			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Deemed contribution - incentive unit compensation \| Predecessor	364,314	364,314
Net income (loss) \| Predecessor	(375,476)				(375,476)
Ending Balance (Predecessor) at Jan. 26, 2017	314,950	710,412	$ 0	0	(395,462)
Ending Balance (in shares) (Predecessor) at Jan. 26, 2017			0
Beginning Balance (Predecessor) at Dec. 31, 2016	326,112	346,098	$ 0	0	(19,986)
Beginning Balance at Dec. 31, 2016	326,112
Beginning Balance (in shares) (Predecessor) at Dec. 31, 2016			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) \| Predecessor	(375,476)
Net income (loss)	(451,934)
Ending Balance at Dec. 31, 2017	699,345	0	$ 2,129	773,674	(76,458)
Ending Balance (in shares) at Dec. 31, 2017			212,931
Beginning Balance (Predecessor) at Jan. 26, 2017	314,950	710,412	$ 0	0	(395,462)
Beginning Balance (in shares) (Predecessor) at Jan. 26, 2017			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock in corporate reorganization		(710,412)	$ 1,846	313,104	395,462
Issuance of common stock in corporate reorganization (in shares)			184,605
Issuance of common stock in initial public offering, net of offering costs	396,991		$ 283	396,708
Issuance of common stock in initial public offering, net of offering costs (in shares)			28,333
Equity-based compensation	63,950			63,950
Vested stock exchanged for tax withholding	(88)			(88)
Common stock reacquired and retired (in shares)			(7)
Net income (loss)	(76,458)				(76,458)
Ending Balance at Dec. 31, 2017	$ 699,345	$ 0	$ 2,129	$ 773,674	$ (76,458)
Ending Balance (in shares) at Dec. 31, 2017			212,931

CONSOLIDATED AND COMBINED STAT7

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (451,934,000)	$ (9,760,000)	$ (7,484,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	111,049,000	40,417,000	22,685,000
Management incentive unit advance	0	(14,712,000)	0
Impairment of unproved oil and natural gas properties	373,000	372,000	6,489,000
Exploratory dry hole costs	0	1,192,000	0
Amortization of debt issuance costs	606,000	260,000	61,000
Deferred income taxes	57,943,000	0	0
Equity-based compensation	442,976,000	0	0
(Gain) loss on commodity derivatives	42,615,000	15,145,000	(1,323,000)
Net cash receipts (payments) on settled derivatives	(2,618,000)	(2,292,000)	5,935,000
Other	882,000	(160,000)	(155,000)
Change in operating assets and liabilities:
Accounts receivable and other current assets	(40,442,000)	(2,588,000)	(5,997,000)
Other assets	(3,000)	11,000	17,000
Accounts payable and accrued liabilities	17,424,000	4,198,000	144,000
Net cash provided by operating activities	178,871,000	32,083,000	20,372,000
CASH FLOWS FROM INVESTING ACTIVITIES
Leasehold and acquisition costs	(73,492,000)	(54,681,000)	(13,716,000)
Development of oil and natural gas properties	(523,559,000)	(139,571,000)	(96,743,000)
Other capital expenditures	(2,983,000)	(1,969,000)	(213,000)
Proceeds from sale of oil and natural gas properties	0	796,000	440,000
Net cash used in investing activities	(600,034,000)	(195,425,000)	(110,232,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock in initial public offering, net of underwriting fees	401,625,000	0	0
Proceeds from JPE LLC members	0	51,542,000	51,000,000
Proceeds from credit facility	165,000,000	112,000,000	20,000,000
Repayment of credit facility	(142,000,000)	0	0
Debt issuance costs	(2,362,000)	(1,220,000)	(603,000)
Costs relating to initial public offering	(3,216,000)	(1,418,000)	0
Employee tax withholding for settlement of equity compensation awards	(88,000)	0	0
Net cash provided by financing activities	418,959,000	160,904,000	70,397,000
NET CHANGE IN CASH AND CASH EQUIVALENTS	(2,204,000)	(2,438,000)	(19,463,000)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	11,727,000	14,165,000	33,628,000
CASH AND CASH EQUIVALENTS, END OF PERIOD	9,523,000	11,727,000	14,165,000
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest	2,021,000	2,190,000	95,000
Cash paid for income taxes	0	0	0
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	105,401,000	36,581,000	17,720,000
Asset retirement obligations	600,000	(100,000)	189,000
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Accrued offering costs	$ 0	$ 1,224,000	$ 0

Organization, Operations and Ba

Organization, Operations and Basis of Presentation	12 Months Ended
Organization, Operations and Basis of Presentation	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Operations and Basis of Presentation	Organization, Operations and Basis of Presentation Organization and Operations Jagged Peak Energy Inc. (either individually or together with its subsidiaries, as the context requires, “Jagged Peak” or the “Company”) is an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves in the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin of West Texas. The Company’s acreage is located on large, contiguous blocks in the adjacent counties of Winkler, Ward, Reeves and Pecos, with significant oil-in-place within multiple stacked hydrocarbon-bearing formations. Corporate Reorganization and Initial Public Offering Jagged Peak is a Delaware corporation formed in September 2016, as a wholly owned subsidiary of Jagged Peak Energy LLC (“JPE LLC”), a Delaware limited liability company formed in April 2013. JPE LLC was formed by an affiliate of Quantum Energy Partners (“Quantum”) and certain members of Jagged Peak’s management team. Jagged Peak was formed to become the holding company of JPE LLC in connection with Jagged Peak’s initial public offering (the “IPO”). Immediately prior to the IPO, all capital interests and management incentive units (“MIUs”) in JPE LLC were converted into a single class of units which were then converted into common stock. Certain members of management and employees contributed a portion of common stock received upon the conversion of unvested or unallocated MIUs to JPE Management Holdings LLC, a limited liability company formed in connection with the IPO for the purpose of holding the unvested or unallocated common stock. Also immediately prior to the IPO, a corporate reorganization (the “corporate reorganization”) took place whereby Jagged Peak, initially formed as a subsidiary of JPE LLC, formed JPE Merger Sub LLC as a subsidiary. JPE LLC merged into JPE Merger Sub LLC, with JPE LLC as the surviving entity. As a result, JPE LLC became a wholly owned subsidiary of Jagged Peak. Prior to the corporate reorganization, Quantum owned 98.6% of the membership interests of JPE LLC. Immediately following the corporate reorganization and IPO, Quantum owned 68.7% of the outstanding common stock of Jagged Peak. As all power and authority to control the core functions of Jagged Peak and JPE LLC were, and continue to be, controlled by Quantum, the corporate reorganization was treated as a reorganization of entities under common control and the results of JPE LLC have been consolidated and combined for all periods. On January 27, 2017, the Company initiated its IPO of common stock to the public, and its common stock began trading on the New York Stock Exchange. During the IPO, the Company and selling stockholders sold 31,599,334 shares at $15.00 per share, raising $474.0 million of gross proceeds. Of the 31,599,334 shares issued to the public, 28,333,334 shares were sold by the Company, and 3,266,000 shares were sold by the selling stockholders. The gross proceeds of the IPO to the Company, based on the public offering price of $15.00 per share, were approximately $425.0 million , which resulted in net proceeds to the Company of $397.0 million after deducting expenses and underwriting discounts and commissions of approximately $28.0 million . The Company did not receive any proceeds from the sale of the shares by the selling stockholders. A portion of the proceeds from the IPO were used to repay the entire outstanding balance on JPE LLC’s credit facility of $142.0 million as of the date the IPO proceeds were received. The remainder of the net proceeds from the IPO were used to fund a portion of the Company’s 2017 capital expenditures program, and for other general corporate purposes. Basis of Presentation The accompanying consolidated and combined financial statements include the accounts of Jagged Peak and JPE LLC, and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These consolidated and combined financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany and intra-company amounts have been eliminated. The consolidated and combined financial statements for periods prior to January 27, 2017 reflect the historical results of JPE LLC, other than the equity-based compensation expense and deferred tax expense, as further described in Notes 6 and 8, respectively. Certain reclassifications have been made to prior period amounts to conform to the current presentation. Industry Segment and Geographic Information The Company evaluated how it is organized and managed, and has identified one operating segment—the production and development of oil and natural gas. All of the Company’s assets are located in the United States, and all of its revenues are attributable to customers located in the United States.

Significant Accounting Policies

Significant Accounting Policies and Related Matters	12 Months Ended
Significant Accounting Policies and Related Matters	Dec. 31, 2017
Accounting Policies [Abstract]
Significant Accounting Policies and Related Matters	Significant Accounting Policies and Related Matters Use of Estimates In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue 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. Although management believes these estimates are reasonable, actual results could differ from these estimates. Estimates made in preparing these consolidated and combined financial statements include, among other things, (1) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment of oil and natural gas properties, (2) operating and capital costs accrued, (3) estimates of timing and costs used in calculating asset retirement obligations, (4) estimates of the fair value of equity-based compensation, (5) estimates used in developing fair value assumptions and estimates, (6) estimates of deferred income taxes and (7) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in estimates, assumptions or actual results could have a significant impact on results in future periods. Fair Value Measurements The Company’s financial instruments are measured at estimated fair value, and consist of derivative instruments, cash and cash equivalents, accounts payable and accrued expenses. The Company’s derivative instruments are measured at fair value on a recurring basis. The carrying amounts of the Company’s other financial instruments are considered to be representative of their fair market value due to their short-term nature. The Company also applies fair value accounting guidance to measure nonfinancial assets and liabilities, such as the acquisition or impairment of oil and gas properties and the inception value of asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. See Note 4, Fair Value Measurements , for further discussion. Cash and Cash Equivalents The Company considers all liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash balances held at commercial banks may at times exceed the Federal Deposit Insurance Corporation limit. The Company has not experienced any credit losses to date. Revenue Recognition Revenue is recognized when production is delivered to a purchaser at a fixed and/or determinable price, title has transferred and the collectability of the revenue is probable. Oil, natural gas and NGL revenue is recorded using the sales method. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. As of December 31, 2017 and 2016 , the Company had no assets or liabilities recorded for oil, natural gas or NGL imbalances. Accounts Receivable The Company’s accounts receivable are generated primarily from the sale of oil, natural gas and NGLs to various customers, from the billing of working interest partners for work on wells the Company operates, and from derivative settlements receivable shortly after the balance sheet date. The Company monitors the financial strength of its customers, partners, and counterparties. At December 31, 2017 and 2016 , the Company did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented. At December 31, 2017 and 2016 , accounts receivable was comprised of the following: December 31, (in thousands) 2017 2016 Oil and gas sales $ 42,869 $ 8,861 Joint interest 7,860 580 Other 5 886 Total accounts receivable $ 50,734 $ 10,327 Significant Customers The Company’s share of oil, natural gas and NGL production is sold to a relatively small number of customers. The loss of any single purchaser could materially and adversely affect the Company’s revenues in the short-term; however, the Company believes that the loss of any of its purchasers would not have a long-term material adverse effect on its financial condition and results of operations as oil and natural gas are fungible products with well-established markets and numerous purchasers. The following purchasers individually accounted for 10% or more of the Company’s total production revenue during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 Trafigura Trading, LLC 78 % 57 % — % Sunoco Partners Marketing 11 % 31 % 68 % Shell Trading (US) Company — % — % 21 % Other Current Assets The components of other current assets are shown below: December 31, (in thousands) 2017 2016 Prepaid expenses $ 607 $ 255 Deferred offering costs — 2,642 Other current assets 199 515 Total other current assets $ 806 $ 3,412 Incremental costs directly related to the IPO were capitalized as deferred offering costs within other current assets until the IPO, at which point these costs were offset against the proceeds received. Derivative Instruments The Company uses commodity derivative instruments to manage its exposure to oil and natural gas price volatility. All of the commodity derivative instruments are utilized to manage price risk attributable to the Company’s expected oil and natural gas production, and the Company does not enter into such instruments for speculative trading purposes. The Company does not designate any derivative instruments as hedges for accounting purposes. The Company records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. The Company records gains and losses from the change in fair value of derivative instruments in current earnings as they occur. The Company currently does not utilize any derivative instruments to manage exposure to variable interest rates, but may do so in the future. The cash flow impact of the Company’s derivative activities is reflected as cash flows from operating activities. See Note 3 , Derivative Instruments , for a more detailed discussion of the Company’s derivative activities. Oil and Natural Gas Properties A summary of the Company’s oil and natural gas properties, net is as follows: December 31, (in thousands) 2017 2016 Proved oil and natural gas properties $ 1,012,321 $ 375,129 Unproved oil and natural gas properties 183,510 155,992 Total oil and natural gas properties 1,195,831 531,121 Less: Accumulated depletion (166,592 ) (57,529 ) Total oil and natural gas properties, net $ 1,029,239 $ 473,592 Proved Oil and Natural Gas Properties The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Under this method, all costs incurred related to the acquisition of oil and natural gas properties and the costs of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when the well is determined not to have recoverable reserves in commercial quantities. Other items charged to expense generally include lease and well operating costs and delay rentals. Geological and geophysical costs directly related to developing proved properties are capitalized. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate. Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement costs, are depleted based on proved developed reserves on a field basis. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded depletion for oil and natural gas properties of $109.2 million , $39.4 million and $22.2 million , respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated and combined statements of operations. Proved oil and natural gas properties are reviewed for impairment when facts and circumstances indicate their carrying value may not be recoverable. The Company estimates the expected future cash flows of 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 estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs, as further discussed in Note 4, Fair Value Measurements . The Company did no t record any impairment expenses associated with its proved properties during the years ended December 31, 2017 , 2016 and 2015 . Unproved Oil and Natural Gas Properties Unproved oil and natural gas properties consist of costs to acquire undeveloped leases and unproved reserves, and are capitalized when incurred. When a successful well is drilled on an undeveloped leasehold or reserves are otherwise attributed to a property, unproved property costs are transferred to proved properties. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Unproved properties are periodically assessed for impairment on a property-by-property basis. 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, and records impairment expense for any decline in value. Impairment of unproved properties for leases which have expired, or are expected to expire, was $0.4 million , $0.4 million and $6.5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Additionally, during 2016 the Company incurred dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon. There were no dry hole costs incurred in 2017 or 2015. Impairments are presented within impairment of unproved oil and natural gas properties, while dry hole costs are presented within exploration expenses on the consolidated and combined statements of operations. Oil and Natural Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the financial statements are estimated in accordance with the rules established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The Company’s annual reserve estimates were prepared by third-party petroleum engineers. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash flows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. See “Supplemental Oil and Natural Gas Disclosures (Unaudited)” following these Notes for a more detailed discussion of the Company’s oil and natural gas reserves. Other Property and Equipment The following table presents the components of other property and equipment, net: December 31, (in thousands) 2017 2016 Other property and equipment $ 12,167 $ 4,760 Less: Accumulated depreciation (2,459 ) (1,759 ) Total other property and equipment, net $ 9,708 $ 3,001 Other property and equipment includes equipment used in drilling and completion activities, the Company’s field office, leasehold improvements, vehicles, IT hardware and software and office furniture, and is recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives, which range from 2 to 20 years. Depreciation expense for the years ended December 31, 2017 , 2016 and 2015 was $1.7 million , $0.9 million and $0.4 million , respectively. When property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounting records. Unamortized Debt Issuance Costs The Company incurred legal and bank fees in connection with obtaining its senior secured revolving credit facility and incurs such fees when increasing bank commitments in conjunction with redetermining an increase in its borrowing base. These costs are stated on the consolidated and combined balance sheets as noncurrent assets at cost, net of amortization, which is computed over the life of the credit facility using the straight-line method and recognized as interest expense on the consolidated and combined statements of operations. Other Noncurrent Assets At December 31, 2017 , other noncurrent assets primarily consists of deposits for office space leases. At December 31, 2016 , other noncurrent assets included a $14.7 million cash advance to management incentive unit advance recipients. The advance was recognized on the consolidated and combined statements of operations as equity-based compensation expense upon the IPO, which was considered a vesting event. See Note 6 , Equity-based Compensation , for more information on the management incentive unit advance. Accrued Liabilities The components of accrued liabilities are shown below: December 31, (in thousands) 2017 2016 Accrued capital expenditures $ 102,956 $ 28,490 Accrued accounts payable 8,488 3,312 Royalties payable 6,105 2,653 Other current liabilities 14,762 4,770 Total accrued liabilities $ 132,311 $ 39,225 Asset Retirement Obligations The Company records a liability for the fair value of an asset retirement obligation (“ARO”) related to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and restoration in accordance with local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized in proved oil and natural gas property costs as part of the carrying cost of the oil and natural gas asset, and depleted over the life of the asset. The recognition of the ARO requires management to make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements, credit-adjusted risk-free discount rates and inflation rates. Revisions to estimated ARO can result from changes in working interest, retirement cost estimates and estimated timing of abandonment. The ARO liability is accreted at the end of each period through charges to accretion expense, which is included in the statements of operations within depletion, depreciation, amortization and accretion expense. Equity-based Compensation The Company recognizes compensation cost related to equity-based awards granted to employees, members of the Company’s board of directors and non-employee contractors in the financial statements based on their estimated grant-date fair value. The Company may grant various types of equity-based awards including stock options, stock appreciation rights, restricted stock, restricted stock units (including awards with service-based vesting and market condition-based vesting provisions), stock awards, dividend equivalents and other types of awards. Service-based restricted stock and units are valued using the market price of Jagged Peak’s common stock on the grant date. The fair value of the market condition-based restricted stock units is based on the grant-date fair value of the award utilizing a Monte Carlo valuation model. Compensation cost is recognized ratably over the applicable vesting period, and is recognized in general and administrative expense on the consolidated and combined statements of operations. The Company has elected to account for forfeitures in compensation expense as they occur. Equity-based compensation arrangements to nonemployees are recognized as expense over the related service period and are subject to remeasurement at the end of each reporting period until they vest. Income Taxes Income taxes are accounted for under the asset and liability method. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses, interest expense and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which the Company operates for the year in which those temporary differences are expected to be recovered or settled. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company classifies all deferred tax assets and liabilities as noncurrent. The Company recognizes the financial statement effects of a tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination. The Company periodically assesses the realizability of its deferred tax assets by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available positive and negative evidence when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences available and tax planning strategies. Deferred tax assets are then reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized. The Company’s accounting predecessor, JPE LLC, was treated as a partnership for federal and state income tax purposes. Accordingly, the accompanying consolidated and combined financial statements do not include a provision or liability for income taxes prior to the corporate reorganization. Earnings per Share The Company uses the treasury stock method to determine the potential dilutive effect of restricted stock units and performance stock units. Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions for participating employees up to a certain percentage of the employee contributions. Matching contributions totaled approximately $0.5 million in the year ended December 31, 2017 , and $0.2 million for each of the years ended December 31, 2016 and 2015 . Benefits under this plan are available to all employees, and employees are fully vested in the employer contribution upon receipt. Recent Accounting Pronouncements In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new guidance requires companies to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-11, which rescinds the SEC accounting guidance regarding the use of the entitlements method for recognition of natural gas revenues. The standards can be adopted using either a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09. The new standards became effective for the Company on January 1, 2018, and the Company has elected to adopt it using the modified retrospective method. The Company evaluated its existing contracts and determined it will not be required to record a cumulative effect adjustment as the new standards did not have a material impact compared to the Company’s current use of the sales method, which is generally consistent with the new standards. The Company implemented the necessary changes to its business processes, systems and controls to support recognition and disclosure of this new standard. While the Company does not expect 2018 net income (loss) or cash flows from operations to be impacted by revenue recognition timing changes, there will be certain changes to the presentation of revenues and related expenses beginning January 1, 2018. If the new standard had been in effect for previous periods, all gathering and transportation expenses would have been included as a reduction to natural gas and NGL sales. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires all leases with a term greater than one year to be recognized on the balance sheet as right-of-use assets and lease liabilities. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. The Company will adopt the new standard on January 1, 2019, using the modified retrospective approach. The Company is in process of evaluating the impact of this new standard, which includes an analysis of existing contracts, including drilling rig and frac fleet contracts, office leases and certain field equipment. The Company is also evaluating the effect of ASU 2016-02 on its current accounting policies and disclosures. The Company believes that adopting the standard will result in increases to the assets and liabilities on its consolidated and combined balance sheets, and changes to the timing and presentation of certain operating expenses on its consolidated and combined statements of operations. The update does not apply to leases of mineral rights to explore for or use oil and natural gas. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842 , which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Company's adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. The Company intends to elect this transition provision. The Company continues to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust its implementation strategies as necessary. In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting . The ASU clarifies which changes to the terms or conditions of an equity-based payment award require an entity to apply modification accounting in Topic 718. The standard became effective for the Company on January 1, 2018. The impact of this new standard will depend on the extent and nature of future changes to the terms of Company's equity-based payment awards.

Derivative Instruments

Derivative Instruments	12 Months Ended
Derivative Instruments	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments The Company hedges a portion of its crude oil sales through derivative instruments to mitigate volatility in commodity prices. The use of these instruments exposes the Company to market basis differential risk if the WTI price does not move in parity with the Company’s underlying sales of crude oil produced in the southern Delaware Basin. The Company also hedges a portion of its market basis differential risk through basis swap contracts. The Company’s derivative instruments are carried at fair value on the consolidated and combined balance sheets. The Company estimates the fair value using risk adjusted discounted cash flow calculations. Cash flows are based on published future commodity price curves for the underlying commodity as of the date of the estimate. Due to the volatility of commodity prices, the estimated fair values of the Company’s derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. For more information, refer to Note 4, Fair Value Measurements . Commodity Price Risk The Company’s principal market risks are its exposure to changes in oil, natural gas and NGL commodity prices. The prices of these commodities are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond the Company’s control. The Company monitors these risks and enters into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on its business. In an effort to reduce the variability of the Company’s cash flows, the Company hedged the commodity prices associated with a portion of its expected future oil volumes by entering into swap and basis swap derivative financial instruments. With swaps, the Company typically receives an agreed upon fixed price for a specified notional quantity of oil or natural gas, and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices. Basis swap contracts establish the differential between Cushing WTI prices and Midland WTI prices, and represent the amount of reduction to Cushing, Oklahoma, prices for the notional volumes contracted. The Company’s commodity derivatives may expose it to the risk of financial loss in certain circumstances. The Company’s derivative arrangements provide protection on the hedged volumes if market prices decline below the prices at which these derivatives are set. If market prices rise above the prices at which the Company has hedged, the Company will be required to make settlement payments to its derivative counterparties. The following table summarizes the Company’s derivative contracts as of December 31, 2017 : Contract Period Volumes Wtd Avg Price Oil Swaps (1) : First quarter 2018 1,315,250 $ 51.86 Second quarter 2018 1,275,500 $ 51.82 Third quarter 2018 1,343,200 $ 52.34 Fourth quarter 2018 1,329,400 $ 52.67 Total 2018 5,263,350 $ 52.18 Year ending December 31, 2019 2,372,500 $ 51.89 Oil Basis Swaps (2) : First quarter 2018 1,260,000 $ (1.08 ) Second quarter 2018 1,274,000 $ (1.08 ) Third quarter 2018 1,288,000 $ (1.08 ) Fourth quarter 2018 1,288,000 $ (1.08 ) Total 2018 5,110,000 $ (1.08 ) Year ending December 31, 2019 2,920,000 $ (1.10 ) (1) The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price. (2) The oil basis swap differential price is between Cushing–WTI and Midland–WTI. The Company has elected to not apply hedge accounting, and as a result, its earnings are affected by the use of the mark-to-market method of accounting for derivative financial instruments. The changes in fair value of these instruments are recognized through earnings as other income or expense rather than deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity price indices. The ultimate gain or loss upon settlement of these transactions is recognized in earnings as other income or expense. Cash settlements of the Company’s derivative contracts are included in cash flows from operating activities in the Company’s statements of cash flows. Subsequent to December 31, 2017 , the Company entered into the following additional derivative contracts: Contract Period Volumes Wtd Avg Price Oil Swaps (1) : First quarter 2018 88,500 $ 60.88 Second quarter 2018 136,500 $ 60.88 Third quarter 2018 138,000 $ 60.88 Fourth quarter 2018 138,000 $ 60.88 Total 2018 501,000 $ 60.88 Oil Basis Swaps (2) : First quarter 2018 88,500 $ (0.03 ) Second quarter 2018 136,500 $ (0.03 ) Third quarter 2018 138,000 $ (0.03 ) Fourth quarter 2018 138,000 $ (0.03 ) Total 2018 501,000 $ (0.03 ) (1) The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price. (2) The oil basis swap differential price is between Cushing–WTI and Midland–WTI. The Company recognized the following gains (losses) and net cash receipts (payments) in earnings for the years ended December 31, 2017 , 2016 and 2015 : (in thousands) 2017 2016 2015 Gain (loss) on derivatives instruments, net $ (42,615 ) $ (15,145 ) $ 1,323 Net cash receipts (payments) on settled derivatives $ (2,618 ) $ (2,292 ) $ 5,935 The Company’s derivative contracts are carried at their fair value on the Company’s consolidated and combined balance sheets using Level 2 inputs, and are subject to industry standard master netting arrangements, which allow the Company to offset recognized asset and liability fair value amounts on contracts with the same counterparty. The Company’s policy is to not offset these positions in its consolidated and combined balance sheets. The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of December 31, 2017 and 2016 (in thousands): As of December 31, 2017: Balance Sheet Location Gross amounts presented on the balance sheet Netting adjustments not offset on the balance sheet Net amounts Assets Commodity contracts Current assets - derivative instruments $ — $ — $ — Commodity contracts Noncurrent assets - derivative instruments 26 (26 ) — Total assets $ 26 $ (26 ) $ — Liabilities Commodity contracts Current liabilities - derivative instruments $ 41,782 $ — $ 41,782 Commodity contracts Noncurrent liabilities - derivative instruments 11,095 (26 ) 11,069 Total liabilities $ 52,877 $ (26 ) $ 52,851 As of December 31, 2016: Balance Sheet Location Gross amounts presented on the balance sheet Netting adjustments not offset on the balance sheet Net amounts Liabilities Commodity contracts Current liabilities - derivative instruments $ 9,567 $ — $ 9,567 Commodity contracts Noncurrent liabilities - derivative instruments 3,287 — 3,287 Total liabilities $ 12,854 $ — $ 12,854 Derivative Counterparty Risk Where the Company is exposed to credit risk in its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement and monitors the appropriateness of these counterparties on an ongoing basis. Generally, the Company does not require collateral and does not anticipate nonperformance by its counterparties. The Company’s counterparty credit exposure related to commodity derivative instruments is represented by contracts with a net positive fair value at the reporting date. These outstanding instruments, if any, expose the Company to credit risk in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of the Company’s counterparties decline, its ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third-party. In the event of a counterparty default, the Company may sustain a loss and its cash receipts could be negatively impacted. At December 31, 2017 , the Company had commodity derivative contracts with three counterparties, all of which were lenders or affiliates of lenders under the Company’s Amended and Restated Credit Facility (as defined in Note 5 , Debt Obligations ) and all of which had investment grade credit ratings. These counterparties accounted for all the Company’s counterparty credit exposure related to commodity derivative assets.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
Fair Value Measurements	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Financial assets and liabilities are measured at fair value on a recurring basis. Nonfinancial assets and liabilities, such as the initial measurement of ARO liabilities and oil and natural gas properties upon acquisition or impairment, are recognized at fair value on a nonrecurring basis. The Company categorizes the inputs to the fair value of its financial assets and liabilities using a three-tier fair value hierarchy, established by the FASB, that prioritizes the significant inputs used in measuring fair value: Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities. Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry standard models that consider various assumptions, including quoted prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in the category include nonexchange-traded derivatives such as over-the-counter forwards, swaps and options. Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value, and the company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Assets and liabilities measured on a recurring basis Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. To determine the fair value at the end of each reporting period, the Company computes discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. The Company compares these prices to the price parameters contained in its hedge contracts to determine estimated future cash inflows or outflows, which are then discounted. The fair values of the Company’s commodity derivative assets and liabilities include a measure of credit risk. These valuations are Level 2 inputs. The following table is a listing of the Company’s assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2017 and 2016 : Level 2 (in thousands) December 31, 2017 December 31, 2016 Assets from commodity derivative contracts $ 26 $ — Liabilities due to commodity derivative contracts $ 52,877 $ 12,854 Assets and liabilities measured on a nonrecurring basis The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its nonfinancial assets and liabilities, such as the acquisition or impairment of proved and unproved oil and gas properties and the inception value of ARO liabilities. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. The Company reviews its proved oil and natural gas properties for impairment whenever facts and circumstances indicate their carrying value may not be recoverable. In such circumstances, the income approach is used to determine the fair value of proved oil and natural gas reserves. Under this approach, the Company estimates the expected future cash flows of 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 estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs. No impairments were recorded on proved properties during the years ended December 31, 2017 , 2016 and 2015 . Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Company uses a market approach, and takes into account future development plans, remaining lease term, drilling results, and reservoir performance. The Company recorded impairment expense on unproved oil and gas properties of $0.4 million , $0.4 million and $6.5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. These impairments resulted from expirations of certain undeveloped leases. The inception value and revision value, if any, of the Company’s AROs are also measured at fair value on a nonrecurring basis. The inputs used to determine such fair value are based primarily on the present value of estimated future cash outflows. Given the unobservable nature of these inputs, they represent Level 3 inputs. The fair value measurements of assets acquired and liabilities assumed in a business acquisition are measured on a nonrecurring basis on the acquisition date using an income valuation approach based on inputs that are unobservable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Fair Value of Other Financial Instruments The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, other current assets, accounts payable, and accrued liabilities that approximate fair value due to the nature of the instrument and the short-term maturities of these instruments.

Debt Obligations

Debt Obligations	12 Months Ended
Debt Obligations	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt Obligations	Debt Obligations In June 2015, JPE LLC entered into a five -year senior secured revolving credit facility (“JPE LLC’s Credit Facility”), with a maximum facility amount of $500.0 million . At December 31, 2016 , JPE LLC’s Credit Facility, as amended, had a borrowing base of $160.0 million , with $132.0 million outstanding under the credit facility, and $28.0 million in unused borrowing capacity. The weighted-average interest rate as of December 31, 2016 was 3.99% . During the year ended December 31, 2016 , JPE LLC capitalized $0.1 million of interest. Following the IPO, the outstanding balance under JPE LLC’s Credit Facility was paid in full. In January 2017, JPE LLC’s Credit Facility borrowing base was increased to $180.0 million . In February 2017, the Company, as parent guarantor, and JPE LLC, as borrower, entered into an amended and restated credit facility with Wells Fargo Bank, N.A., as administrative agent and the lenders thereto (the “Amended and Restated Credit Facility”). The borrowing base remained at $180.0 million , while the maximum facility amount increased to $1.0 billion . Borrowings under the Amended and Restated Credit Facility bore interest at a rate elected by the Company that was equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% , and the thirty-day adjusted LIBOR plus 1.0% ) or LIBOR, in each case, plus the applicable margin. The applicable margin ranged from 1.25% to 2.25% in the case of the alternative base rate and from 2.25% to 3.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company paid a commitment fee of 0.50% per year on the unused portion of the borrowing base. The Amended and Restated Credit Facility matures on February 1, 2022, and is subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year. The borrowing base increased from $180.0 million to $250.0 million after the April 2017 redetermination. In October 2017, the Company and JPE LLC entered into an amendment to the Amended and Restated Credit Facility (“Amendment No. 1”). Under Amendment No. 1, the borrowing base increased to $425.0 million and the pricing grid was lowered. Following Amendment No. 1, the Amended and Restated Credit Facility remains subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year. Borrowings under the Amended and Restated Credit Facility following Amendment No. 1 bore interest at a rate elected by the Company that was equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% , and the thirty-day adjusted LIBOR plus 1.0% ) or LIBOR, in each case, plus the applicable margin. The applicable margin ranged from 1.00% to 2.00% in the case of the alternative base rate, and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company paid a commitment fee of 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base. Amendment No. 1 is secured by oil and natural gas properties representing at least 90% of the value of the Company’s proved reserves. Amendment No. 1 contains certain covenants, including among others, restrictions on indebtedness, restrictions on liens, restrictions on investments, restrictions on mergers, restrictions on sales of assets, restrictions on dividends and payments to the Company’s capital interest holders and restrictions on the Company’s hedging activity. Amendment No. 1 contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Agreement, include requirements to comply with the following financial ratios: • a current ratio, which is the ratio of consolidated current assets (including unused commitments under the credit facility and excluding noncash assets related to ARO and derivatives) to consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and noncash liabilities related to ARO and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0 ; and • a leverage ratio, which is the ratio of consolidated Debt (as defined in the credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in the credit agreement) to EBITDAX (as defined in the credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0 . As of December 31, 2017 , the Company was in compliance with its financial covenants. As of December 31, 2017 , there was $155.0 million outstanding under Amendment No. 1 of the Amended and Restated Credit Facility. The weighted-average interest rate as of December 31, 2017 was 3.68% . During the year ended December 31, 2017 , the Company capitalized $0.3 million of interest. In March 2018, the Company entered into Amendment No. 2 to the Amended and Restated Credit Facility which extended the maturity date of the Amended and Restated Credit Facility to March 2023, increased the maximum facility amount to $1.5 billion , increased the borrowing base to $540.0 million , increased the hedging limits and lowered the pricing grid. Borrowings under the Amended and Restated Credit Facility following Amendment No. 2 bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% , and the thirty-day adjusted LIBOR plus 1.0% ) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate, and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The commitment fee paid by the Company remains at 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.

Equity-based Compensation

Equity-based Compensation	12 Months Ended
Equity-based Compensation	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-based Compensation	Equity-based Compensation In connection with the IPO, the Company adopted the Jagged Peak Energy Inc. 2017 Long Term Incentive Plan (the “Plan”), which allows the Company to grant up to 21,200,000 equity-based compensation shares to employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, performance awards and other types of awards. The terms and conditions of the awards granted are established by the Company’s Board of Directors. Shares issued as a result of awards granted under the Plan are generally new common shares. Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated and combined statements of operations, was as follows for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 2015 Incentive unit awards $ 439,411 $ — $ — Restricted stock unit awards 1,616 — — Performance stock unit awards 1,497 — — Restricted stock unit awards issued to nonemployee directors 452 — — Total equity-based compensation expense $ 442,976 $ — $ — Incentive Unit Awards In connection with its formation in April 2013, JPE LLC established an incentive pool plan, whereby JPE LLC granted MIUs to employees and selected other participants. The MIUs were considered “profits interests” that participated in certain events whereupon distributions would be made to MIU holders (only after certain return thresholds were achieved by the capital interests) following a qualifying initial public offering, sale, merger, or other qualifying transaction involving the units or assets of JPE LLC (“Vesting Event”). The MIUs were accounted for under FASB ASC Topic 710, Compensation–General , which requires compensation expense for the MIUs to be recognized when all performance, market and service conditions are probable of being satisfied, which is generally upon a Vesting Event. As of and through December 31, 2016, the vesting of the MIUs was not deemed probable, therefore no expense was recognized through December 31, 2016. The corporate reorganization provided a mechanism by which all capital interests and MIUs in JPE LLC were converted into a single class of units, which were then converted into the Company’s common stock. A portion of these shares vested and a portion were transferred to JPE Management Holdings LLC (“Management Holdco”) and became subject to the terms and conditions of the amended and restated JPE Management Holdings LLC limited liability company agreement (the “Management Holdco LLC Agreement”). As a result of the IPO, the satisfaction of all conditions relating to MIUs in JPE LLC held by the current and former officers and employees who owned equity interests in JPE LLC, was deemed probable. As a result, based on the Company’s IPO price of $15.00 per share, compensation expense of $379.0 million was recognized for the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016. The $14.7 million is included in the consolidated and combined statements of cash flows as an operating activity for the year ended 2016 . The shares of common stock transferred to Management Holdco are accounted for under ASC 718, Compensation–Stock Compensation , and generally vest over three years. During the year ended December 31, 2017 , the Company recognized $60.4 million of equity-based compensation expense related to the shares held by Management Holdco. Included in the $60.4 million is $22.2 million of equity-based compensation related to awards held by Management Holdco which were modified in conjunction with a March 2017 separation agreement of a former executive officer. The remaining compensation expense of these awards will be recognized ratably according to the terms of the Management Holdco LLC Agreement. The equity-based compensation relative to these shares of common stock transferred to Management Holdco is not deductible for federal or state income tax purposes. A summary of incentive unit award activity for the year ended December 31, 2017 is as follows: Weighted Average Grant-date Incentive Units Fair Value Unvested at Corporate Reorganization 9,570,280 $ 15.00 Granted 235,346 $ 12.45 Vested (2,049,881 ) $ 14.97 Forfeited — $ — Unvested at December 31, 2017 7,755,745 $ 14.93 Compensation costs remaining at December 31, 2017 (in millions) $ 80.6 Weighted average remaining period at December 31, 2017 (in years) 2.1 The total fair value of incentive units that vested from the IPO date to December 31, 2017 was $25.2 million . At December 31, 2017 , there were 431,321 of unallocated shares of Company common stock held at Management Holdco. When these shares are granted, they will be valued using the closing stock price on the date of grant, and the Company will recognize the related expense over the requisite service period. In February 2018, certain employees notified the Company of their desire to terminate their employment. Under the terms of the Management Holdco LLC Agreement, upon voluntary termination of employment by an incentive unit award holder, the Board of Directors has the discretion to allow outstanding unvested incentive unit awards to immediately vest, to continue to vest post-termination, and/or to be automatically forfeited, or any combination thereof. Any forfeited incentive units are reallocated to the remaining incentive unit holders employed by the Company. In February 2018, the Board of Directors modified these employees’ unvested incentive units to either immediately accelerate vesting, in the case of retiring employees, or continue to vest post-termination under the original vesting period. The Company determined that these are accounted for as modifications under ASC 718 in the first quarter of 2018. As a result of these modifications to the service requirements, the Company determined that, for accounting purposes under ASC 718, the incentive unit awards allocated at IPO no longer met the substantive service condition, and that any previously unrecognized equity-based compensation expense should be recognized immediately. The acceleration of all previously unrecognized equity-based compensation expense for incentive unit awards allocated at the time of the IPO will result in the recognition of approximately $71.2 million of noncash equity-based compensation expense in the first quarter of 2018. This accounting does not alter the legal service obligations under the Management Holdco LLC Agreement for remaining employees whose awards were not modified. Equity-based compensation expense recognition related to incentive unit awards that were unallocated at the time of the IPO is unaffected. Restricted Stock Unit Awards Restricted stock unit awards (“RSUs”) vest subject to the satisfaction of service requirements. Expense related to each RSU award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur through reversal of expense on awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. A summary of RSU award activity for the year ended December 31, 2017 is as follows: Weighted Average Grant-date RSUs Fair Value Unvested at December 31, 2016 — $ — Granted 588,894 $ 12.45 Vested — $ — Forfeited (5,921 ) $ 12.61 Unvested at December 31, 2017 582,973 $ 12.44 Compensation costs remaining at December 31, 2017 (in millions) $ 5.2 Weighted average remaining period at December 31, 2017 (in years) 2.2 Of the 588,894 RSUs granted during 2017 , nonemployee directors received 55,744 at a weighted average grant-date fair value of $12.46 . The remaining compensation costs at December 31, 2017 for these nonemployee director RSUs was $0.2 million , with a weighted average remaining period of 0.4 years. Performance Stock Unit Awards During 2017 , the Company granted performance stock unit awards (“PSUs”) to certain of its officers, which vest based on continuous employment and satisfaction of a performance metric based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR of a peer group of companies over an approximate three -year performance period ending December 31, 2019. The number of shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over approximately three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. A summary of PSU award activity for the year ended December 31, 2017 is as follows: Weighted Average Grant-date PSUs Fair Value Unvested at December 31, 2016 — $ — Granted 398,566 $ 16.32 Vested — $ — Forfeited — $ — Unvested at December 31, 2017 398,566 $ 16.32 Compensation costs remaining at December 31, 2017 (in millions) $ 5.0 Weighted average remaining period at December 31, 2017 (in years) 2.0 The grant-date fair value of the PSUs was determined using a Monte Carlo simulation, which uses a probabilistic approach for estimating the fair value of the awards. The expected volatility was derived from a weighted combination of implied volatility and historical volatility. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs. The following table presents information regarding the weighted average fair value for PSUs granted during the year ended December 31, 2017 and the assumptions used to determine the fair values: Year Ended December 31, 2017 Dividend yield — % Volatility 55.7 % Risk-free interest rate 1.34 % Weighted average fair value of awards granted $ 16.32

Earnings Per Share

Earnings Per Share	12 Months Ended
Earnings Per Share	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share (“EPS”) is computed by dividing net earnings by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested RSUs and PSUs, if including such potential shares of common stock units is dilutive. The PSUs included in the calculation of diluted weighted average shares outstanding are based on the number of shares of common stock that would be issuable if the end of the reporting period was the end of the performance period required for the vesting of such PSU awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all awards is anti-dilutive. For the year ended December 31, 2017 , the Company’s EPS calculation includes only the net loss for the period subsequent to the corporate reorganization and IPO, and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017, to December 31, 2017 . A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: From January 27, 2017, to (in thousands, except per share amounts) December 31, 2017 Net income (loss) attributable to Jagged Peak Energy Inc. stockholders $ (76,458 ) Basic weighted average shares outstanding 212,932 Effect of dilutive securities: Restricted stock units — Performance stock units — Diluted weighted average shares outstanding 212,932 Net income (loss) per common share: Basic $ (0.36 ) Diluted $ (0.36 ) The following table presents amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be anti-dilutive: From January 27, 2017, to (in thousands) December 31, 2017 Weighted average number of outstanding equity awards excluded from diluted earnings per share calculation: (1) Restricted stock units 411 Performance stock units 523 (1) When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be anti-dilutive.

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes JPE LLC was organized as a limited liability company and treated as a pass-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of the Company from January 27, 2017 through December 31, 2017 in the accompanying consolidated and combined financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the change in tax status as a result of the corporate reorganization, the Company established an $80.7 million provision for deferred income taxes, which was recognized as tax expense from continuing operations. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate to 21%, (ii) repeals the corporate alternative minimum tax, (iii) imposes new limitations on the utilization of net operating losses and eliminates their carryforward restrictions and (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. In addition, the Tax Act preserves deductibility of intangible drilling costs and provides for 100% bonus depreciation on tangible personal property expenditures through 2022. The bonus depreciation percentage is phased down from 100% beginning in 2023 to 0% for years after 2026. The Company recognizes the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted or signed into law. The SEC issued rules that would allow for a measurement period of up to one year after the enactment date of the Tax Act to finalize the impact of the Tax Act on a company's financial statements. The Company has substantially completed the analysis of the Tax Act and does not expect a material change due to the transition impacts. Any changes that do arise due to changes in interpretations of the Tax Act, legislative action to address questions that arise because of the Tax Act, changes in accounting standards for income taxes or related interpretations in response to the Tax Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise. The components of the Company’s provision for income taxes are as follows: Year Ended (in thousands) December 31, 2017 Current income tax expense: Federal $ — State — — Deferred income tax expense: Federal 56,350 State 1,593 57,943 Provision for income taxes $ 57,943 A reconciliation of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense is as follows: Year Ended (in thousands) December 31, 2017 Income (loss) before income taxes $ (393,991 ) Less: loss before income taxes prior to corporate reorganization (375,476 ) Income (loss) before income taxes subsequent to corporate reorganization $ (18,515 ) Income tax expense (benefit) at the federal statutory rate $ (6,480 ) Income tax expense relating to change in tax status 80,704 Federal tax reform changes - 2017 Tax Act (37,282 ) State income taxes, net of federal benefit 199 Nondeductible equity-based compensation 20,781 Other permanent differences 21 Income tax expense (benefit) $ 57,943 Effective tax rate (14.7 )% Prior to the Company’s change in tax status in January 2017, income taxes did not significantly impact the results of operations. The equity-based compensation related to shares of common stock transferred to Management Holdco is not deductible for federal or state income tax purposes. See Note 6 , Equity-based Compensation , for more information on the shares of common stock transferred to Management Holdco. The components of the Company’s deferred income tax assets and liabilities as of December 31, 2017 are as follows: (in thousands) December 31, 2017 Deferred income tax assets: Commodity derivatives $ 11,412 Equity-based compensation 928 Net operating loss carryforwards 16,093 Other 1,726 30,159 Deferred income tax liabilities: Oil and natural gas properties 88,102 88,102 Net deferred income tax assets (liabilities) $ (57,943 ) The Company had U.S. net operating losses of approximately $16.1 million , which expire in 2037 . Deferred tax assets are reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized. The Company periodically assesses its deferred tax assets for realizability and, as a result of such assessment, determined as of December 31, 2017 sufficient evidence existed to indicate it is more likely than not that its deferred tax assets will be realized. The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. That Company gives financial statement recognition to those tax provisions that it believes are more likely than not to be sustained upon examination by the Internal Revenue Service or other government agency. As of December 31, 2017 , the Company did no t have any accrued liability for unrecognized tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. At December 31, 2017 , the Company has made no provisions for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction, Texas and Colorado. There are currently no federal or state income tax examinations underway. The Company’s U.S. federal income tax returns remain open to examination by the taxing authorities for tax years 2014 through 2017 , and its Texas and Colorado tax returns remain open to examination for the years 2013 through 2017 .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The following table summarizes the changes in the carrying amount of the ARO liabilities for the years ended December 31, 2017 and 2016 . Any ARO classified as current is included in accrued liabilities on the consolidated and combined balance sheets. (in thousands) 2017 2016 Asset retirement obligations at January 1, $ 448 $ 608 Liabilities incurred and assumed 590 138 Liability settlements and disposals (190 ) (127 ) Revisions of estimated liabilities 9 (224 ) Accretion 72 53 Asset retirement obligations at December 31, 929 448 Less current portion of asset retirement obligations (118 ) — Long-term asset retirement obligations $ 811 $ 448 In 2017 and 2016 , the Company recognized revisions of estimated liabilities totaling $9 thousand and $0.2 million , respectively, which were due to changes in working interest and estimated abandonment timing and costs.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments The table below shows the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2017 : (in thousands) 2018 2019 2020 2021 2022 Thereafter Total Operating leases (1) $ 2,052 $ 1,490 $ 1,514 $ 1,535 $ 1,552 $ 8,962 $ 17,105 Service and purchase contracts (2) 2,380 1,287 1,285 750 — — 5,702 Rig contracts 16,054 — — — — — 16,054 Frac fleet contracts 73,200 — — — — — 73,200 Total $ 93,686 $ 2,777 $ 2,799 $ 2,285 $ 1,552 $ 8,962 $ 112,061 (1) Primarily relates to the lease of the Company’s corporate offices. (2) Primarily relates to a retail power sales agreement and seismic data gathering contract. Office and equipment operating lease commitments The Company leases office space in Denver, Colorado, and Midland, Texas. The Company’s lease for its initial corporate office space in Denver expires in September 2018, and in December 2017 the Company moved into a new corporate office space. The Company’s new corporate office lease in Denver expires in 2028. In connection with this lease, the Company received $4.7 million of lease incentives primarily related to tenant improvements, which is recorded within other long-term liabilities on the consolidated and combined balance sheets. The lease incentive liability is amortized on a straight-line basis as a reduction to rent expense over the lease term. The tenant improvements are depreciated over the shorter of the useful life of the asset or the life of the lease. The Company also leases certain office equipment under operating leases, which expire over the next five years. Rent expense with respect to these lease commitments was approximately $0.9 million for the year ended December 31, 2017 , and $0.6 million for each of the years ended December 31, 2016 and 2015 . In January 2018, the Company entered into a termination agreement on its initial corporate office lease, in which the Company agreed to a one-time termination fee of approximately $0.3 million . Including this fee, the 2018 operating lease commitment would be $1.8 million . Drilling rig commitments At December 31, 2017 , the Company had six drilling rigs under contract. If the Company were to terminate these contracts at December 31, 2017 , it would be required to pay early termination penalties of $7.5 million . In 2016 and 2015, the Company terminated one drilling rig in each year and incurred early termination charges of approximately $0.2 million and $0.3 million , respectively. These charges are reflected as other operating costs on the consolidated and combined statements of operations. Frac fleet commitments At December 31, 2017 , the Company had three frac fleets under contract through December 31, 2018 . The majority of the contracts allow for reassignment of the frac fleets to another operator if the Company were to terminate their services prior to the end of the contract, at which point the Company would not be required to pay termination fees. However, if the fleets were not able to be reassigned, the Company would be required to pay termination fees of $57.2 million as of December 31, 2017 . Contingencies Legal Matters 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. Environmental Matters The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both December 31, 2017 and 2016 , the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Related Party Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Quantum employs certain members of the Company’s board of directors and had significant capital interests in JPE LLC. As of December 31, 2017 , Quantum owns 68.7% of the Company’s common stock. Quantum owns a 41.5% interest in Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”). The Company has a 12 -year crude oil gathering agreement with Oryx whereby Oryx provides midstream gathering services to the Company. Under that agreement, the Company has the right to designate, and has designated, a third-party shipper to market the Company’s crude oil. In addition, the Company paid fees to Oryx for the purchase and maintenance of connecting equipment. Quantum also owns a 60.9% interest in Phoenix Lease Services, LLC (“Phoenix”), and an indirect interest in Trident Water Services, LLC (“Trident”), a wholly owned subsidiary of Phoenix. The Company regularly leases frac tanks and other oil field equipment from Phoenix, and regularly uses water transfer services provided by Trident. The Company is under no obligation to use either provider, and both provide services only when selected as a vendor through the Company’s normal bidding process. The following table summarizes fees paid to Oryx, Phoenix and Trident for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 2015 Oryx via 3rd party shipper (1) $ 10,058 $ 2,125 $ — Oryx (2) $ 798 $ 1,765 $ 425 Phoenix (3) $ 366 $ 338 $ 361 Trident (3) $ 236 $ 590 $ 1,041 (1) Transportation fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil gathering agreement are netted against revenue as they are included in the net price paid by to the third-party shipper. (2) Fees paid to Oryx for the purchase and installation of connecting equipment are capitalized to proved properties on the consolidated and combined balance sheets. (3) Fees paid to Phoenix and Trident are capitalized to proved properties on the consolidated and combined balance sheets. At December 31, 2017 and 2016 , the Company had outstanding payables to these related parties of $1.8 million and $0.7 million , respectively.

Significant Accounting Polici19

Significant Accounting Policies and Related Matters (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated and combined financial statements include the accounts of Jagged Peak and JPE LLC, and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These consolidated and combined financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany and intra-company amounts have been eliminated. The consolidated and combined financial statements for periods prior to January 27, 2017 reflect the historical results of JPE LLC, other than the equity-based compensation expense and deferred tax expense, as further described in Notes 6 and 8, respectively.
Reclassifications	Certain reclassifications have been made to prior period amounts to conform to the current presentation.
Industry Segment and Geographic Information	Industry Segment and Geographic Information The Company evaluated how it is organized and managed, and has identified one operating segment—the production and development of oil and natural gas. All of the Company’s assets are located in the United States, and all of its revenues are attributable to customers located in the United States.
Use of Estimates	Use of Estimates In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue 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. Although management believes these estimates are reasonable, actual results could differ from these estimates. Estimates made in preparing these consolidated and combined financial statements include, among other things, (1) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment of oil and natural gas properties, (2) operating and capital costs accrued, (3) estimates of timing and costs used in calculating asset retirement obligations, (4) estimates of the fair value of equity-based compensation, (5) estimates used in developing fair value assumptions and estimates, (6) estimates of deferred income taxes and (7) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in estimates, assumptions or actual results could have a significant impact on results in future periods.
Fair Value Measurements	Fair Value Measurements The Company’s financial instruments are measured at estimated fair value, and consist of derivative instruments, cash and cash equivalents, accounts payable and accrued expenses. The Company’s derivative instruments are measured at fair value on a recurring basis. The carrying amounts of the Company’s other financial instruments are considered to be representative of their fair market value due to their short-term nature. The Company also applies fair value accounting guidance to measure nonfinancial assets and liabilities, such as the acquisition or impairment of oil and gas properties and the inception value of asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. See Note 4, Fair Value Measurements , for further discussion.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash balances held at commercial banks may at times exceed the Federal Deposit Insurance Corporation limit. The Company has not experienced any credit losses to date.
Revenue Recognition	Revenue Recognition Revenue is recognized when production is delivered to a purchaser at a fixed and/or determinable price, title has transferred and the collectability of the revenue is probable. Oil, natural gas and NGL revenue is recorded using the sales method. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers.
Accounts Receivable	Accounts Receivable The Company’s accounts receivable are generated primarily from the sale of oil, natural gas and NGLs to various customers, from the billing of working interest partners for work on wells the Company operates, and from derivative settlements receivable shortly after the balance sheet date. The Company monitors the financial strength of its customers, partners, and counterparties.
Significant Customers	Significant Customers The Company’s share of oil, natural gas and NGL production is sold to a relatively small number of customers. The loss of any single purchaser could materially and adversely affect the Company’s revenues in the short-term; however, the Company believes that the loss of any of its purchasers would not have a long-term material adverse effect on its financial condition and results of operations as oil and natural gas are fungible products with well-established markets and numerous purchasers.
Deferred Offering Costs	Incremental costs directly related to the IPO were capitalized as deferred offering costs within other current assets until the IPO, at which point these costs were offset against the proceeds received. Unamortized Debt Issuance Costs The Company incurred legal and bank fees in connection with obtaining its senior secured revolving credit facility and incurs such fees when increasing bank commitments in conjunction with redetermining an increase in its borrowing base. These costs are stated on the consolidated and combined balance sheets as noncurrent assets at cost, net of amortization, which is computed over the life of the credit facility using the straight-line method and recognized as interest expense on the consolidated and combined statements of operations.
Derivative Instruments	Derivative Instruments The Company uses commodity derivative instruments to manage its exposure to oil and natural gas price volatility. All of the commodity derivative instruments are utilized to manage price risk attributable to the Company’s expected oil and natural gas production, and the Company does not enter into such instruments for speculative trading purposes. The Company does not designate any derivative instruments as hedges for accounting purposes. The Company records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. The Company records gains and losses from the change in fair value of derivative instruments in current earnings as they occur. The Company currently does not utilize any derivative instruments to manage exposure to variable interest rates, but may do so in the future.
Oil and Natural Gas Properties	Proved Oil and Natural Gas Properties The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Under this method, all costs incurred related to the acquisition of oil and natural gas properties and the costs of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when the well is determined not to have recoverable reserves in commercial quantities. Other items charged to expense generally include lease and well operating costs and delay rentals. Geological and geophysical costs directly related to developing proved properties are capitalized. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate. Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement costs, are depleted based on proved developed reserves on a field basis. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded depletion for oil and natural gas properties of $109.2 million , $39.4 million and $22.2 million , respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated and combined statements of operations. Proved oil and natural gas properties are reviewed for impairment when facts and circumstances indicate their carrying value may not be recoverable. The Company estimates the expected future cash flows of 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 estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs, as further discussed in Note 4, Fair Value Measurements . The Company did no t record any impairment expenses associated with its proved properties during the years ended December 31, 2017 , 2016 and 2015 . Unproved Oil and Natural Gas Properties Unproved oil and natural gas properties consist of costs to acquire undeveloped leases and unproved reserves, and are capitalized when incurred. When a successful well is drilled on an undeveloped leasehold or reserves are otherwise attributed to a property, unproved property costs are transferred to proved properties. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Unproved properties are periodically assessed for impairment on a property-by-property basis. 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, and records impairment expense for any decline in value. Impairment of unproved properties for leases which have expired, or are expected to expire, was $0.4 million , $0.4 million and $6.5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Additionally, during 2016 the Company incurred dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon. There were no dry hole costs incurred in 2017 or 2015. Impairments are presented within impairment of unproved oil and natural gas properties, while dry hole costs are presented within exploration expenses on the consolidated and combined statements of operations. Oil and Natural Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the financial statements are estimated in accordance with the rules established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The Company’s annual reserve estimates were prepared by third-party petroleum engineers. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash flows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. See “Supplemental Oil and Natural Gas Disclosures (Unaudited)” following these Notes for a more detailed discussion of the Company’s oil and natural gas reserves.
Other Property and Equipment	Other property and equipment includes equipment used in drilling and completion activities, the Company’s field office, leasehold improvements, vehicles, IT hardware and software and office furniture, and is recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives, which range from 2 to 20 years. Depreciation expense for the years ended December 31, 2017 , 2016 and 2015 was $1.7 million , $0.9 million and $0.4 million , respectively. When property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounting records. Other Property and Equipment
Equity-based Compensation and Other Noncurrent Assets	Equity-based Compensation The Company recognizes compensation cost related to equity-based awards granted to employees, members of the Company’s board of directors and non-employee contractors in the financial statements based on their estimated grant-date fair value. The Company may grant various types of equity-based awards including stock options, stock appreciation rights, restricted stock, restricted stock units (including awards with service-based vesting and market condition-based vesting provisions), stock awards, dividend equivalents and other types of awards. Service-based restricted stock and units are valued using the market price of Jagged Peak’s common stock on the grant date. The fair value of the market condition-based restricted stock units is based on the grant-date fair value of the award utilizing a Monte Carlo valuation model. Compensation cost is recognized ratably over the applicable vesting period, and is recognized in general and administrative expense on the consolidated and combined statements of operations. The Company has elected to account for forfeitures in compensation expense as they occur. Equity-based compensation arrangements to nonemployees are recognized as expense over the related service period and are subject to remeasurement at the end of each reporting period until they vest.
Asset Retirement Obligations	Asset Retirement Obligations The Company records a liability for the fair value of an asset retirement obligation (“ARO”) related to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and restoration in accordance with local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized in proved oil and natural gas property costs as part of the carrying cost of the oil and natural gas asset, and depleted over the life of the asset. The recognition of the ARO requires management to make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements, credit-adjusted risk-free discount rates and inflation rates. Revisions to estimated ARO can result from changes in working interest, retirement cost estimates and estimated timing of abandonment. The ARO liability is accreted at the end of each period through charges to accretion expense, which is included in the statements of operations within depletion, depreciation, amortization and accretion expense.
Income Taxes	Income Taxes Income taxes are accounted for under the asset and liability method. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses, interest expense and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which the Company operates for the year in which those temporary differences are expected to be recovered or settled. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company classifies all deferred tax assets and liabilities as noncurrent. The Company recognizes the financial statement effects of a tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination. The Company periodically assesses the realizability of its deferred tax assets by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available positive and negative evidence when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences available and tax planning strategies. Deferred tax assets are then reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized.
Earnings per Share	Earnings per Share The Company uses the treasury stock method to determine the potential dilutive effect of restricted stock units and performance stock units.
Defined Contribution Plan	Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions for participating employees up to a certain percentage of the employee contributions. Matching contributions totaled approximately $0.5 million in the year ended December 31, 2017 , and $0.2 million for each of the years ended December 31, 2016 and 2015 . Benefits under this plan are available to all employees, and employees are fully vested in the employer contribution upon receipt.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new guidance requires companies to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-11, which rescinds the SEC accounting guidance regarding the use of the entitlements method for recognition of natural gas revenues. The standards can be adopted using either a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09. The new standards became effective for the Company on January 1, 2018, and the Company has elected to adopt it using the modified retrospective method. The Company evaluated its existing contracts and determined it will not be required to record a cumulative effect adjustment as the new standards did not have a material impact compared to the Company’s current use of the sales method, which is generally consistent with the new standards. The Company implemented the necessary changes to its business processes, systems and controls to support recognition and disclosure of this new standard. While the Company does not expect 2018 net income (loss) or cash flows from operations to be impacted by revenue recognition timing changes, there will be certain changes to the presentation of revenues and related expenses beginning January 1, 2018. If the new standard had been in effect for previous periods, all gathering and transportation expenses would have been included as a reduction to natural gas and NGL sales. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires all leases with a term greater than one year to be recognized on the balance sheet as right-of-use assets and lease liabilities. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. The Company will adopt the new standard on January 1, 2019, using the modified retrospective approach. The Company is in process of evaluating the impact of this new standard, which includes an analysis of existing contracts, including drilling rig and frac fleet contracts, office leases and certain field equipment. The Company is also evaluating the effect of ASU 2016-02 on its current accounting policies and disclosures. The Company believes that adopting the standard will result in increases to the assets and liabilities on its consolidated and combined balance sheets, and changes to the timing and presentation of certain operating expenses on its consolidated and combined statements of operations. The update does not apply to leases of mineral rights to explore for or use oil and natural gas. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842 , which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Company's adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. The Company intends to elect this transition provision. The Company continues to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust its implementation strategies as necessary. In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting . The ASU clarifies which changes to the terms or conditions of an equity-based payment award require an entity to apply modification accounting in Topic 718. The standard became effective for the Company on January 1, 2018. The impact of this new standard will depend on the extent and nature of future changes to the terms of Company's equity-based payment awards.

Significant Accounting Polici20

Significant Accounting Policies and Related Matters (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Accounts Receivable	At December 31, 2017 and 2016 , accounts receivable was comprised of the following: December 31, (in thousands) 2017 2016 Oil and gas sales $ 42,869 $ 8,861 Joint interest 7,860 580 Other 5 886 Total accounts receivable $ 50,734 $ 10,327
Schedules of Concentration of Risk, by Risk Factor	The following purchasers individually accounted for 10% or more of the Company’s total production revenue during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 Trafigura Trading, LLC 78 % 57 % — % Sunoco Partners Marketing 11 % 31 % 68 % Shell Trading (US) Company — % — % 21 %
Schedule of Other Current Assets	The components of other current assets are shown below: December 31, (in thousands) 2017 2016 Prepaid expenses $ 607 $ 255 Deferred offering costs — 2,642 Other current assets 199 515 Total other current assets $ 806 $ 3,412
Oil, Natural Gas Properties, Property, Plant and Equipment	The following table presents the components of other property and equipment, net: December 31, (in thousands) 2017 2016 Other property and equipment $ 12,167 $ 4,760 Less: Accumulated depreciation (2,459 ) (1,759 ) Total other property and equipment, net $ 9,708 $ 3,001 A summary of the Company’s oil and natural gas properties, net is as follows: December 31, (in thousands) 2017 2016 Proved oil and natural gas properties $ 1,012,321 $ 375,129 Unproved oil and natural gas properties 183,510 155,992 Total oil and natural gas properties 1,195,831 531,121 Less: Accumulated depletion (166,592 ) (57,529 ) Total oil and natural gas properties, net $ 1,029,239 $ 473,592
Schedule of Accrued Liabilities	The components of accrued liabilities are shown below: December 31, (in thousands) 2017 2016 Accrued capital expenditures $ 102,956 $ 28,490 Accrued accounts payable 8,488 3,312 Royalties payable 6,105 2,653 Other current liabilities 14,762 4,770 Total accrued liabilities $ 132,311 $ 39,225

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
Derivative Instruments (Tables)	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	Subsequent to December 31, 2017 , the Company entered into the following additional derivative contracts: Contract Period Volumes Wtd Avg Price Oil Swaps (1) : First quarter 2018 88,500 $ 60.88 Second quarter 2018 136,500 $ 60.88 Third quarter 2018 138,000 $ 60.88 Fourth quarter 2018 138,000 $ 60.88 Total 2018 501,000 $ 60.88 Oil Basis Swaps (2) : First quarter 2018 88,500 $ (0.03 ) Second quarter 2018 136,500 $ (0.03 ) Third quarter 2018 138,000 $ (0.03 ) Fourth quarter 2018 138,000 $ (0.03 ) Total 2018 501,000 $ (0.03 ) (1) The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price. (2) The oil basis swap differential price is between Cushing–WTI and Midland–WTI. The following table summarizes the Company’s derivative contracts as of December 31, 2017 : Contract Period Volumes Wtd Avg Price Oil Swaps (1) : First quarter 2018 1,315,250 $ 51.86 Second quarter 2018 1,275,500 $ 51.82 Third quarter 2018 1,343,200 $ 52.34 Fourth quarter 2018 1,329,400 $ 52.67 Total 2018 5,263,350 $ 52.18 Year ending December 31, 2019 2,372,500 $ 51.89 Oil Basis Swaps (2) : First quarter 2018 1,260,000 $ (1.08 ) Second quarter 2018 1,274,000 $ (1.08 ) Third quarter 2018 1,288,000 $ (1.08 ) Fourth quarter 2018 1,288,000 $ (1.08 ) Total 2018 5,110,000 $ (1.08 ) Year ending December 31, 2019 2,920,000 $ (1.10 ) (1) The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price. (2) The oil basis swap differential price is between Cushing–WTI and Midland–WTI.
Derivative Instruments, Gain (Loss)	The Company recognized the following gains (losses) and net cash receipts (payments) in earnings for the years ended December 31, 2017 , 2016 and 2015 : (in thousands) 2017 2016 2015 Gain (loss) on derivatives instruments, net $ (42,615 ) $ (15,145 ) $ 1,323 Net cash receipts (payments) on settled derivatives $ (2,618 ) $ (2,292 ) $ 5,935
Schedule of Derivative Instruments by Balance Sheet Location	The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of December 31, 2017 and 2016 (in thousands): As of December 31, 2017: Balance Sheet Location Gross amounts presented on the balance sheet Netting adjustments not offset on the balance sheet Net amounts Assets Commodity contracts Current assets - derivative instruments $ — $ — $ — Commodity contracts Noncurrent assets - derivative instruments 26 (26 ) — Total assets $ 26 $ (26 ) $ — Liabilities Commodity contracts Current liabilities - derivative instruments $ 41,782 $ — $ 41,782 Commodity contracts Noncurrent liabilities - derivative instruments 11,095 (26 ) 11,069 Total liabilities $ 52,877 $ (26 ) $ 52,851 As of December 31, 2016: Balance Sheet Location Gross amounts presented on the balance sheet Netting adjustments not offset on the balance sheet Net amounts Liabilities Commodity contracts Current liabilities - derivative instruments $ 9,567 $ — $ 9,567 Commodity contracts Noncurrent liabilities - derivative instruments 3,287 — 3,287 Total liabilities $ 12,854 $ — $ 12,854

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table is a listing of the Company’s assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2017 and 2016 : Level 2 (in thousands) December 31, 2017 December 31, 2016 Assets from commodity derivative contracts $ 26 $ — Liabilities due to commodity derivative contracts $ 52,877 $ 12,854

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	12 Months Ended
Equity-based Compensation (Tables)	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated and combined statements of operations, was as follows for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 2015 Incentive unit awards $ 439,411 $ — $ — Restricted stock unit awards 1,616 — — Performance stock unit awards 1,497 — — Restricted stock unit awards issued to nonemployee directors 452 — — Total equity-based compensation expense $ 442,976 $ — $ —
Schedule of Share-based Compensation, Incentive Units, Activity	A summary of incentive unit award activity for the year ended December 31, 2017 is as follows: Weighted Average Grant-date Incentive Units Fair Value Unvested at Corporate Reorganization 9,570,280 $ 15.00 Granted 235,346 $ 12.45 Vested (2,049,881 ) $ 14.97 Forfeited — $ — Unvested at December 31, 2017 7,755,745 $ 14.93 Compensation costs remaining at December 31, 2017 (in millions) $ 80.6 Weighted average remaining period at December 31, 2017 (in years) 2.1
Schedule of Nonvested Restricted Stock Units Activity	A summary of RSU award activity for the year ended December 31, 2017 is as follows: Weighted Average Grant-date RSUs Fair Value Unvested at December 31, 2016 — $ — Granted 588,894 $ 12.45 Vested — $ — Forfeited (5,921 ) $ 12.61 Unvested at December 31, 2017 582,973 $ 12.44 Compensation costs remaining at December 31, 2017 (in millions) $ 5.2 Weighted average remaining period at December 31, 2017 (in years) 2.2
Share-based Compensation, Performance Shares Award Unvested Activity	A summary of PSU award activity for the year ended December 31, 2017 is as follows: Weighted Average Grant-date PSUs Fair Value Unvested at December 31, 2016 — $ — Granted 398,566 $ 16.32 Vested — $ — Forfeited — $ — Unvested at December 31, 2017 398,566 $ 16.32 Compensation costs remaining at December 31, 2017 (in millions) $ 5.0 Weighted average remaining period at December 31, 2017 (in years) 2.0
Schedule of Assumptions Used	The following table presents information regarding the weighted average fair value for PSUs granted during the year ended December 31, 2017 and the assumptions used to determine the fair values: Year Ended December 31, 2017 Dividend yield — % Volatility 55.7 % Risk-free interest rate 1.34 % Weighted average fair value of awards granted $ 16.32

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
Earnings Per Share (Tables)	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Earnings Per Share	A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: From January 27, 2017, to (in thousands, except per share amounts) December 31, 2017 Net income (loss) attributable to Jagged Peak Energy Inc. stockholders $ (76,458 ) Basic weighted average shares outstanding 212,932 Effect of dilutive securities: Restricted stock units — Performance stock units — Diluted weighted average shares outstanding 212,932 Net income (loss) per common share: Basic $ (0.36 ) Diluted $ (0.36 )
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following table presents amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be anti-dilutive: From January 27, 2017, to (in thousands) December 31, 2017 Weighted average number of outstanding equity awards excluded from diluted earnings per share calculation: (1) Restricted stock units 411 Performance stock units 523 (1) When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be anti-dilutive.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of the Company’s provision for income taxes are as follows: Year Ended (in thousands) December 31, 2017 Current income tax expense: Federal $ — State — — Deferred income tax expense: Federal 56,350 State 1,593 57,943 Provision for income taxes $ 57,943
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense is as follows: Year Ended (in thousands) December 31, 2017 Income (loss) before income taxes $ (393,991 ) Less: loss before income taxes prior to corporate reorganization (375,476 ) Income (loss) before income taxes subsequent to corporate reorganization $ (18,515 ) Income tax expense (benefit) at the federal statutory rate $ (6,480 ) Income tax expense relating to change in tax status 80,704 Federal tax reform changes - 2017 Tax Act (37,282 ) State income taxes, net of federal benefit 199 Nondeductible equity-based compensation 20,781 Other permanent differences 21 Income tax expense (benefit) $ 57,943 Effective tax rate (14.7 )%
Schedule of Deferred Tax Assets and Liabilities	The components of the Company’s deferred income tax assets and liabilities as of December 31, 2017 are as follows: (in thousands) December 31, 2017 Deferred income tax assets: Commodity derivatives $ 11,412 Equity-based compensation 928 Net operating loss carryforwards 16,093 Other 1,726 30,159 Deferred income tax liabilities: Oil and natural gas properties 88,102 88,102 Net deferred income tax assets (liabilities) $ (57,943 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	The following table summarizes the changes in the carrying amount of the ARO liabilities for the years ended December 31, 2017 and 2016 . Any ARO classified as current is included in accrued liabilities on the consolidated and combined balance sheets. (in thousands) 2017 2016 Asset retirement obligations at January 1, $ 448 $ 608 Liabilities incurred and assumed 590 138 Liability settlements and disposals (190 ) (127 ) Revisions of estimated liabilities 9 (224 ) Accretion 72 53 Asset retirement obligations at December 31, 929 448 Less current portion of asset retirement obligations (118 ) — Long-term asset retirement obligations $ 811 $ 448

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	The table below shows the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2017 : (in thousands) 2018 2019 2020 2021 2022 Thereafter Total Operating leases (1) $ 2,052 $ 1,490 $ 1,514 $ 1,535 $ 1,552 $ 8,962 $ 17,105 Service and purchase contracts (2) 2,380 1,287 1,285 750 — — 5,702 Rig contracts 16,054 — — — — — 16,054 Frac fleet contracts 73,200 — — — — — 73,200 Total $ 93,686 $ 2,777 $ 2,799 $ 2,285 $ 1,552 $ 8,962 $ 112,061 (1) Primarily relates to the lease of the Company’s corporate offices. (2) Primarily relates to a retail power sales agreement and seismic data gathering contract.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes fees paid to Oryx, Phoenix and Trident for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 2015 Oryx via 3rd party shipper (1) $ 10,058 $ 2,125 $ — Oryx (2) $ 798 $ 1,765 $ 425 Phoenix (3) $ 366 $ 338 $ 361 Trident (3) $ 236 $ 590 $ 1,041 (1) Transportation fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil gathering agreement are netted against revenue as they are included in the net price paid by to the third-party shipper. (2) Fees paid to Oryx for the purchase and installation of connecting equipment are capitalized to proved properties on the consolidated and combined balance sheets. (3) Fees paid to Phoenix and Trident are capitalized to proved properties on the consolidated and combined balance sheets.

Organization, Operations and 29

Organization, Operations and Basis of Presentation (Details) $ / shares in Units, $ in Thousands	Jan. 27, 2017USD ($)$ / sharesshares	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Gross proceeds		$ 401,625	$ 0	$ 0
Expenses and underwriting discounts and commissions		$ 3,216	$ 1,418	$ 0
Number of operating segments \| segment		1
Quantum
Debt Instrument [Line Items]
Ownership interest			98.60%
Ownership percent after IPO		68.70%
Line of Credit \| JPE LLC
Debt Instrument [Line Items]
Credit facility repayments	$ 142,000
IPO
Debt Instrument [Line Items]
Shares sold (in shares) \| shares	31,599,334
Price per share (in dollars per share) \| $ / shares	$ 15
Proceeds raised	$ 474,000
IPO \| Quantum
Debt Instrument [Line Items]
Ownership percent after IPO		68.70%
IPO Sold by Company
Debt Instrument [Line Items]
Shares sold (in shares) \| shares	28,333,334
Gross proceeds	$ 425,000
Net proceeds	397,000
Expenses and underwriting discounts and commissions	$ 28,000
IPO Sold by Stockholders
Debt Instrument [Line Items]
Shares sold (in shares) \| shares	3,266,000

Significant Accounting Polici30

Significant Accounting Policies and Related Matters - Narrative (Details) - USD ($)	1 Months Ended		12 Months Ended
	Jan. 26, 2017	Apr. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Assets or liabilities recorded for oil, natural gas or NGL imbalances			$ 0	$ 0
Depletion			109,200,000	39,400,000	$ 22,200,000
Proved property impairment			0	0	0
Impairment of unproved property for leases			373,000	372,000	6,489,000
Dry hole costs			0	1,192,000	0
Depreciation expense			1,700,000	900,000	400,000
Cash advance			442,976,000	0	0
Matching contributions			500,000	200,000	200,000
Incentive unit awards
Concentration Risk [Line Items]
Cash advance	$ 379,000,000	$ 14,700,000	$ 439,411,000	$ 0	$ 0
Minimum \| Property, Plant and Equipment, Other Types
Concentration Risk [Line Items]
Estimated useful lives			P2Y
Maximum \| Property, Plant and Equipment, Other Types
Concentration Risk [Line Items]
Estimated useful lives			P20Y

Significant Accounting Polici31

Significant Accounting Policies and Related Matters - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 50,734	$ 10,327
Oil and gas sales
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	42,869	8,861
Joint interest
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	7,860	580
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 5	$ 886

Significant Accounting Polici32

Significant Accounting Policies and Related Matters - Schedules of Concentration of Risk, by Risk Factor (Details) - Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Trafigura Trading, LLC
Concentration Risk [Line Items]
Concentration risk percent	78.00%	57.00%	0.00%
Sunoco Partners Marketing
Concentration Risk [Line Items]
Concentration risk percent	11.00%	31.00%	68.00%
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk percent	0.00%	0.00%	21.00%

Significant Accounting Polici33

Significant Accounting Policies and Related Matters - Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Prepaid expenses	$ 607	$ 255
Deferred offering costs	0	2,642
Other current assets	199	515
Total other current assets	$ 806	$ 3,412

Significant Accounting Polici34

Significant Accounting Policies and Related Matters - Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Proved oil and natural gas properties	$ 1,012,321	$ 375,129
Unproved oil and natural gas properties	183,510	155,992
Total oil and natural gas properties	1,195,831	531,121
Less: Accumulated depletion	(166,592)	(57,529)
Total oil and gas properties, net	$ 1,029,239	$ 473,592

Significant Accounting Polici35

Significant Accounting Policies and Related Matters - Other Property And Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Total property and equipment, net	$ 1,038,947	$ 476,593
Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
Other property and equipment	12,167	4,760
Less: Accumulated depreciation	(2,459)	(1,759)
Total property and equipment, net	$ 9,708	$ 3,001

Significant Accounting Polici36

Significant Accounting Policies and Related Matters - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Accrued capital expenditures	$ 102,956	$ 28,490
Accrued accounts payable	8,488	3,312
Royalties payable	6,105	2,653
Other current liabilities	14,762	4,770
Total accrued liabilities	$ 132,311	$ 39,225

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Derivatives (Details) - Not Designated as Hedging Instrument	Mar. 21, 2018$ / bblbbl	Dec. 31, 2017$ / bblbbl
First quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,315,250
Wtd Avg Price ($/Bbl) \| $ / bbl		(51.86)
Second quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,275,500
Wtd Avg Price ($/Bbl) \| $ / bbl		(51.82)
Third quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,343,200
Wtd Avg Price ($/Bbl) \| $ / bbl		(52.34)
Fourth quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,329,400
Wtd Avg Price ($/Bbl) \| $ / bbl		(52.67)
Total 2,018
Derivative [Line Items]
Volumes (Bbls) \| bbl		5,263,350
Wtd Avg Price ($/Bbl) \| $ / bbl		(52.18)
Year ending December 31, 2019
Derivative [Line Items]
Volumes (Bbls) \| bbl		2,372,500
Wtd Avg Price ($/Bbl) \| $ / bbl		(51.89)
First quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,260,000
Wtd Avg Price ($/Bbl) \| $ / bbl		(1.08)
Second quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,274,000
Wtd Avg Price ($/Bbl) \| $ / bbl		(1.08)
Third quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,288,000
Wtd Avg Price ($/Bbl) \| $ / bbl		(1.08)
Fourth quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl		1,288,000
Wtd Avg Price ($/Bbl) \| $ / bbl		(1.08)
Total 2,018
Derivative [Line Items]
Volumes (Bbls) \| bbl		5,110,000
Wtd Avg Price ($/Bbl) \| $ / bbl		(1.08)
Year ending December 31, 2019
Derivative [Line Items]
Volumes (Bbls) \| bbl		2,920,000
Wtd Avg Price ($/Bbl) \| $ / bbl		(1.10)
Subsequent Event \| First quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	88,500
Wtd Avg Price ($/Bbl) \| $ / bbl	(60.88)
Subsequent Event \| Second quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	136,500
Wtd Avg Price ($/Bbl) \| $ / bbl	(60.88)
Subsequent Event \| Third quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	138,000
Wtd Avg Price ($/Bbl) \| $ / bbl	(60.88)
Subsequent Event \| Fourth quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	138,000
Wtd Avg Price ($/Bbl) \| $ / bbl	(60.88)
Subsequent Event \| Total 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	501,000
Wtd Avg Price ($/Bbl) \| $ / bbl	(60.88)
Subsequent Event \| First quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	88,500
Wtd Avg Price ($/Bbl) \| $ / bbl	(0.03)
Subsequent Event \| Second quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	136,500
Wtd Avg Price ($/Bbl) \| $ / bbl	(0.03)
Subsequent Event \| Third quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	138,000
Wtd Avg Price ($/Bbl) \| $ / bbl	(0.03)
Subsequent Event \| Fourth quarter 2018
Derivative [Line Items]
Volumes (Bbls) \| bbl	138,000
Wtd Avg Price ($/Bbl) \| $ / bbl	(0.03)
Subsequent Event \| Year ending December 31, 2019
Derivative [Line Items]
Volumes (Bbls) \| bbl	501,000
Wtd Avg Price ($/Bbl) \| $ / bbl	(0.03)

Derivative Instruments - Gains

Derivative Instruments - Gains (Losses) in Earnings (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gain (loss) on derivatives instruments, net	$ (42,615)	$ (15,145)	$ 1,323
Net cash receipts (payments) on settled derivatives	$ (2,618)	$ (2,292)	$ 5,935

Derivative Instruments - Balanc

Derivative Instruments - Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, assets	$ 26
Netting adjustments not offset on the balance sheet, assets	(26)
Assets from commodity derivative contracts, assets	0
Gross amounts presented on the balance sheet, liabilities	52,877	$ 12,854
Netting adjustments not offset on the balance sheet, liabilities	(26)	0
Liabilities from commodity derivative contracts, liabilities	52,851	12,854
Commodity contracts \| Current assets - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, assets	0
Netting adjustments not offset on the balance sheet, assets	0
Assets from commodity derivative contracts, assets	0
Commodity contracts \| Noncurrent assets - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, assets	26
Netting adjustments not offset on the balance sheet, assets	(26)
Assets from commodity derivative contracts, assets	0
Commodity contracts \| Current liabilities - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, liabilities	41,782	9,567
Netting adjustments not offset on the balance sheet, liabilities	0	0
Liabilities from commodity derivative contracts, liabilities	41,782	9,567
Commodity contracts \| Noncurrent liabilities - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, liabilities	11,095	3,287
Netting adjustments not offset on the balance sheet, liabilities	(26)	0
Liabilities from commodity derivative contracts, liabilities	$ 11,069	$ 3,287

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details)	Dec. 31, 2017counterparty
Commodity contracts
Derivative [Line Items]
Number of counterparties	3

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative contracts	$ 26
Liabilities due to commodity derivative contracts	52,877	$ 12,854
Impairment of unproved oil and natural gas properties	373	372	$ 6,489
Recurring \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative contracts	26	0
Liabilities due to commodity derivative contracts	52,877	12,854
Proved Oil and Gas Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of unproved oil and natural gas properties	$ 0	$ 0	$ 0

Debt Obligations (Details)

Debt Obligations (Details) - USD ($)	1 Months Ended				12 Months Ended
Debt Obligations (Details) - USD ($)	Mar. 22, 2018	Oct. 31, 2017	Feb. 28, 2017	Jun. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Apr. 30, 2017	Jan. 31, 2017
Debt Instrument [Line Items]
Balance outstanding					$ 155,000,000	$ 132,000,000
Revolving Credit Facility \| Amended and Restated Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 1,000,000,000
Current borrowing capacity			$ 180,000,000				$ 250,000,000
Weighted average interest rate					3.68%
Capitalized interest					$ 300,000
Commitment fee			0.50%
Percent of proved reserves (at least)			90.00%
Minimum current ratio			1
Maximum leverage ratio			4
Revolving Credit Facility \| Amended and Restated Credit Facility \| Federal Funds Effective Rate
Debt Instrument [Line Items]
Basis spread on variable rate			0.50%
Revolving Credit Facility \| Amended and Restated Credit Facility \| Federal Funds Effective Rate \| Minimum
Debt Instrument [Line Items]
Basis spread on variable rate			1.25%
Revolving Credit Facility \| Amended and Restated Credit Facility \| Federal Funds Effective Rate \| Maximum
Debt Instrument [Line Items]
Basis spread on variable rate			2.25%
Revolving Credit Facility \| Amended and Restated Credit Facility \| LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate			1.00%
Revolving Credit Facility \| Amended and Restated Credit Facility \| LIBOR \| Minimum
Debt Instrument [Line Items]
Basis spread on variable rate			2.25%
Revolving Credit Facility \| Amended and Restated Credit Facility \| LIBOR \| Maximum
Debt Instrument [Line Items]
Basis spread on variable rate			3.25%
Revolving Credit Facility \| Amendment No. 1
Debt Instrument [Line Items]
Current borrowing capacity		$ 425,000,000
Revolving Credit Facility \| Amendment No. 1 \| Minimum
Debt Instrument [Line Items]
Commitment fee		0.375%
Revolving Credit Facility \| Amendment No. 1 \| Maximum
Debt Instrument [Line Items]
Commitment fee		0.50%
Revolving Credit Facility \| Amendment No. 1 \| Federal Funds Effective Rate
Debt Instrument [Line Items]
Basis spread on variable rate		0.50%
Revolving Credit Facility \| Amendment No. 1 \| Federal Funds Effective Rate \| Minimum
Debt Instrument [Line Items]
Basis spread on variable rate		1.00%
Revolving Credit Facility \| Amendment No. 1 \| Federal Funds Effective Rate \| Maximum
Debt Instrument [Line Items]
Basis spread on variable rate		2.00%
Revolving Credit Facility \| Amendment No. 1 \| LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate		1.00%
Revolving Credit Facility \| Amendment No. 1 \| LIBOR \| Minimum
Debt Instrument [Line Items]
Basis spread on variable rate		2.00%
Revolving Credit Facility \| Amendment No. 1 \| LIBOR \| Maximum
Debt Instrument [Line Items]
Basis spread on variable rate		3.00%
JPE LLC \| Revolving Credit Facility \| The Credit Facility
Debt Instrument [Line Items]
Debt term				5 years
Maximum borrowing capacity				$ 500,000,000
Current borrowing capacity						160,000,000
Balance outstanding						132,000,000
Borrowing capacity remaining						$ 28,000,000
Weighted average interest rate						3.99%
Capitalized interest						$ 100,000
JPE LLC \| Revolving Credit Facility \| The Amended Credit Facility
Debt Instrument [Line Items]
Current borrowing capacity								$ 180,000,000
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 1,500,000,000
Current borrowing capacity	$ 540,000,000
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| Minimum
Debt Instrument [Line Items]
Commitment fee	0.375%
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| Maximum
Debt Instrument [Line Items]
Commitment fee	0.50%
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| Federal Funds Effective Rate
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| Federal Funds Effective Rate \| Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| Federal Funds Effective Rate \| Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	1.50%
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| LIBOR \| Minimum
Debt Instrument [Line Items]
Basis spread on variable rate	1.50%
Subsequent Event \| Revolving Credit Facility \| Amendment No. 2 \| LIBOR \| Maximum
Debt Instrument [Line Items]
Basis spread on variable rate	2.50%

Equity-based Compensation - Add

Equity-based Compensation - Additional Information (Details) - USD ($)	1 Months Ended		3 Months Ended	12 Months Ended
	Jan. 26, 2017	Apr. 30, 2016	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 27, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation awards authorized for grant (up to) (in shares)				21,200,000
Equity-based compensation				$ 442,976,000	$ 0	$ 0
Incentive unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 379,000,000	$ 14,700,000		$ 439,411,000	0	0
Vesting period				3 years
Fair value of vested units				$ 25,200,000
Granted (in shares)				235,346
Weighted average grant date fair value (in dollars per share)				$ 12.45
Compensation costs remaining				$ 80,600,000
Weighted average remaining period				2 years 1 month 6 days
Restricted stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation				$ 1,616,000	0	0
Granted (in shares)				588,894
Weighted average grant date fair value (in dollars per share)				$ 12.45
Compensation costs remaining				$ 5,200,000
Weighted average remaining period				2 years 2 months 12 days
Performance stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation				$ 1,497,000	$ 0	$ 0
Granted (in shares)				398,566
Weighted average grant date fair value (in dollars per share)				$ 16.32
Compensation costs remaining				$ 5,000,000
Weighted average remaining period				2 years
Performance awards service period				3 years
IPO
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Price per share (in dollars per share)							$ 15
Management Holdco \| Incentive unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation				$ 60,400,000
Unallocated shares held (in shares)				431,321
Management Holdco \| Incentive unit awards, former executive officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation modification				$ 22,200,000
Minimum \| Performance stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of units granted				0.00%
Maximum \| Performance stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of units granted				200.00%
Nonemployee Director \| Restricted stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				55,744
Weighted average grant date fair value (in dollars per share)				$ 12.46
Compensation costs remaining				$ 200,000
Weighted average remaining period				4 months 24 days
Scenario, Forecast \| Management Holdco \| Incentive unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation			$ 71,200,000

Equity-based Compensation - Sha

Equity-based Compensation - Share-based Compensation Expense (Details) - USD ($)	1 Months Ended		12 Months Ended
	Jan. 26, 2017	Apr. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total equity-based compensation expense			$ 442,976,000	$ 0	$ 0
Incentive unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total equity-based compensation expense	$ 379,000,000	$ 14,700,000	439,411,000	0	0
Restricted stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total equity-based compensation expense			1,616,000	0	0
Performance stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total equity-based compensation expense			1,497,000	0	0
Restricted stock unit awards issued to nonemployee directors
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total equity-based compensation expense			$ 452,000	$ 0	$ 0

Equity-based Compensation - Sto

Equity-based Compensation - Stock Options Activity (Details) - Profit Interest Awards $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Incentive Units
Unvested beginning balance (in shares) \| shares	9,570,280
Granted (in shares) \| shares	235,346
Vested (in shares) \| shares	(2,049,881)
Forfeited (in shares) \| shares	0
Unvested ending balance (in shares) \| shares	7,755,745
Compensation costs remaining \| $	$ 80.6
Weighted average remaining period	2 years 1 month 6 days
Weighted Average Grant-date Fair Value
Unvested beginning balance (in dollars per share) \| $ / shares	$ 15
Granted (in dollars per share) \| $ / shares	12.45
Vested (in dollars per share) \| $ / shares	14.97
Forfeited (in dollars per share) \| $ / shares	0
Unvested ending balance (in dollars per share) \| $ / shares	$ 14.93

Equity-based Compensation - Non

Equity-based Compensation - Nonvested Restricted Stock Units Activity (Details) - Restricted stock unit awards $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
RSUs
Unvested beginning balance (in shares) \| shares	0
Granted (in shares) \| shares	588,894
Vested (in shares) \| shares	0
Forfeited (in shares) \| shares	(5,921)
Unvested ending balance (in shares) \| shares	582,973
Compensation costs remaining \| $	$ 5.2
Weighted average remaining period	2 years 2 months 12 days
Weighted Average Grant-date Fair Value
Unvested beginning balance (in dollars per share) \| $ / shares	$ 0
Granted (in dollars per share) \| $ / shares	12.45
Vested (in dollars per share) \| $ / shares	0
Forfeited (in dollars per share) \| $ / shares	12.61
Unvested ending balance (in dollars per share) \| $ / shares	$ 12.44

Equity-based Compensation - N47

Equity-based Compensation - Nonvested Performance Shares Award Activity (Details) - PSUs $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
PSUs
Unvested beginning balance (in shares) \| shares	0
Granted (in shares) \| shares	398,566
Vested (in shares) \| shares	0
Forfeited (in shares) \| shares	0
Unvested ending balance (in shares) \| shares	398,566
Compensation costs remaining \| $	$ 5
Weighted average remaining period	2 years
Weighted Average Grant-date Fair Value
Unvested beginning balance (in dollars per share) \| $ / shares	$ 0
Granted (in dollars per share) \| $ / shares	16.32
Vested (in dollars per share) \| $ / shares	0
Forfeited (in dollars per share) \| $ / shares	0
Unvested ending balance (in dollars per share) \| $ / shares	$ 16.32

Equity-based Compensation - Val

Equity-based Compensation - Valuation Assumptions (Details) - Performance stock unit awards	12 Months Ended
	Dec. 31, 2017$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividend yield	0.00%
Volatility	55.70%
Risk-free interest rate	1.34%
Weighted average fair value of awards granted (in dollars per share)	$ 16.32

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Line Items]
Net income (loss)	$ (76,458)	$ (451,934)	$ (9,760)	$ (7,484)
Weighted average shares outstanding - basic (in shares)	212,932	212,932
Effect of dilutive securities:
Diluted weighted average shares outstanding (in shares)	212,932	212,932
Net income (loss) per common share:
Basic (in dollars per share)	$ (0.36)	$ (0.36)
Diluted (in dollars per share)	$ (0.36)	$ (0.36)
Restricted stock unit awards
Effect of dilutive securities:
Effect of dilutive securities (in shares)	0
Performance stock unit awards
Effect of dilutive securities:
Effect of dilutive securities (in shares)	0

Earnings Per Share - Antidiluti

Earnings Per Share - Antidilutive Securities (Details) shares in Thousands	11 Months Ended
	Dec. 31, 2017shares
Restricted stock unit awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average number of outstanding equity awards excluded from diluted earnings per share calculation (in shares)	411
Performance stock unit awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average number of outstanding equity awards excluded from diluted earnings per share calculation (in shares)	523

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details)	12 Months Ended
Income Taxes - Narrative (Details)	Dec. 31, 2017USD ($)
Income Tax Disclosure [Abstract]
Deferred income taxes	$ 80,700,000
Operating loss carryforwards, domestic	16,100,000
Unrecognized tax benefits	0
Income tax penalties and interest accrued	$ 0

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current income tax expense:
Federal	$ 0
State	0
Current income taxes	0
Deferred income tax expense:
Federal	56,350
State	1,593
Deferred income taxes	57,943	$ 0	$ 0
Provision for income taxes	$ 57,943	$ 0	$ 0

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	1 Months Ended	11 Months Ended	12 Months Ended
	Jan. 26, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal statutory rate			35.00%
Income (loss) before income taxes	$ (375,476)	$ (18,515)	$ (393,991)	$ (9,760)	$ (7,484)
Income tax expense (benefit) at the federal statutory rate			(6,480)
Income tax expense relating to change in tax status			80,704
Federal tax reform changes - 2017 Tax Act			(37,282)
State income taxes, net of federal benefit			199
Nondeductible equity-based compensation			20,781
Other permanent differences			21
Provision for income taxes			$ 57,943	$ 0	$ 0
Effective tax rate			(14.70%)

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) $ in Thousands	Dec. 31, 2017USD ($)
Deferred income tax assets:
Commodity derivatives	$ 11,412
Equity-based compensation	928
Net operating loss carryforwards	16,093
Other	1,726
Total deferred tax assets	30,159
Deferred income tax liabilities:
Oil and natural gas properties	88,102
Total deferred tax liabilities	88,102
Net deferred income tax assets (liabilities)	$ (57,943)

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning balance	$ 448	$ 608
Liabilities incurred and assumed	590	138
Liability settlements and disposals	(190)	(127)
Revisions of estimated liabilities	9	(224)
Accretion	72	53
Asset retirement obligation, ending balance	929	448
Less current portion of asset retirement obligations	(118)	0
Long-term asset retirement obligations	$ 811	$ 448

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Minimum Rental Payments for Operating Leases (Details) $ in Thousands	Dec. 31, 2017USD ($)
Operating Leased Assets [Line Items]
2,018	$ 93,686
2,019	2,777
2,020	2,799
2,021	2,285
2,022	1,552
Thereafter	8,962
Total	112,061
Operating leases
Operating Leased Assets [Line Items]
2,018	2,052
2,019	1,490
2,020	1,514
2,021	1,535
2,022	1,552
Thereafter	8,962
Total	17,105
Service and purchase contracts
Operating Leased Assets [Line Items]
2,018	2,380
2,019	1,287
2,020	1,285
2,021	750
2,022	0
Thereafter	0
Total	5,702
Rig contracts
Operating Leased Assets [Line Items]
2,018	16,054
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	0
Total	16,054
Frac fleet contracts
Operating Leased Assets [Line Items]
2,018	73,200
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	0
Total	$ 73,200

Commitments and Contingencies57

Commitments and Contingencies - Narrative (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)contractfrac_fleet_contract	Dec. 31, 2016USD ($)contract	Dec. 31, 2015USD ($)contract	Jan. 01, 2018USD ($)
Loss Contingencies [Line Items]
Lease incentives		$ 4,700
Rent expense		900	$ 600	$ 600
Lease commitment		$ 112,061
Number of drilling rig contracts \| contract		6
Early termination penalties		$ 7,500
Number of drilling rig contracts terminated \| contract			1	1
Early termination charges			$ 200	$ 300
Frac fleet contracts
Loss Contingencies [Line Items]
Frac fleet under contract \| frac_fleet_contract		3
Termination fees		$ 57,200
Subsequent Event
Loss Contingencies [Line Items]
Termination fee	$ 300
Lease commitment					$ 1,800
Office Equipment
Loss Contingencies [Line Items]
Lease expiration period		5 years

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Outstanding payables	$ 1.8	$ 0.7
Quantum
Related Party Transaction [Line Items]
Ownership percent after IPO	68.70%
Ownership interest		98.60%
IPO \| Quantum
Related Party Transaction [Line Items]
Ownership percent after IPO	68.70%
Oryx Midstream Services, LLC \| Oil Gathering Agreement
Related Party Transaction [Line Items]
Contract agreement term	12 years
Investee \| Oryx Midstream Services, LLC \| Quantum
Related Party Transaction [Line Items]
Ownership interest	41.50%
Investee \| Phoenix Lease Services, LLC \| Quantum
Related Party Transaction [Line Items]
Ownership interest	60.90%

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Phoenix Lease Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	$ 366	$ 338	$ 361
Trident Water Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	236	590	1,041
Oil Gathering Agreement \| Oryx Midstream Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	10,058	2,125	0
Leasing of Equipment \| Oryx Midstream Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	$ 798	$ 1,765	$ 425