Jagged Peak Energy 10-K 28 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Feb. 22, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Document Fiscal Year Focus	2,018
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
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	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		213,358,572
Entity Current Reporting Status	Yes
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 754

CONSOLIDATED AND COMBINED BALAN

CONSOLIDATED AND COMBINED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 35,229	$ 9,523
Accounts receivable	61,186	50,734
Derivative instruments	103,092	0
Other current assets	1,627	806
Total current assets	201,134	61,063
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method	1,905,498	1,195,831
Accumulated depletion	(386,883)	(166,592)
Total oil and gas properties, net	1,518,615	1,029,239
Other property and equipment, net	11,670	9,708
Total property and equipment, net	1,530,285	1,038,947
OTHER NONCURRENT ASSETS
Unamortized debt issuance costs	3,704	3,273
Derivative instruments	31,899	26
Other assets	119	119
Total noncurrent assets	35,722	3,418
TOTAL ASSETS	1,767,141	1,103,428
CURRENT LIABILITIES
Accounts payable	34,762	382
Accrued liabilities	130,012	132,311
Derivative instruments	23,208	41,782
Total current liabilities	187,982	174,475
LONG-TERM LIABILITIES
Long-term debt	489,239	155,000
Derivative instruments	11,162	11,095
Asset retirement obligations	1,946	811
Deferred income taxes	124,418	57,943
Other long-term liabilities	4,444	4,759
Total long-term liabilities	631,209	229,608
Commitments and contingencies
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value; 50,000,000 shares authorized, none issued	0	0
Common stock, $0.01 par value; 1,000,000,000 shares authorized, 213,187,780 shares issued at December 31, 2018; 212,930,655 shares issued at December 31, 2017	2,132	2,129
Additional paid-in capital	856,818	773,674
Retained Earnings (Accumulated deficit)	89,000	(76,458)
Total stockholders' equity	947,950	699,345
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 1,767,141	$ 1,103,428

CONSOLIDATED AND COMBINED STATE

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
REVENUES
Total revenues	$ 581,644	$ 267,312	$ 76,522
OPERATING EXPENSES
Lease operating expenses	42,406	17,874	7,505
Gathering and processing expenses	0	4,424	1,046
Production and ad valorem taxes	34,642	16,120	4,345
Exploration	29	31	2,484
Depletion, depreciation, amortization and accretion	222,355	111,049	40,417
Impairment of unproved oil and natural gas properties	28,198	373	372
General and administrative expenses (including equity-based compensation of $83,346, $442,976 and $0 in 2018, 2017 and 2016, respectively)	122,472	466,067	11,690
Other operating expenses	63	247	649
Total operating expenses	450,165	616,185	68,508
INCOME (LOSS) FROM OPERATIONS	131,479	(348,873)	8,014
OTHER INCOME (EXPENSE)
Gain (loss) on commodity derivatives	119,338	(42,615)	(15,145)
Interest expense, net	(25,152)	(2,861)	(2,629)
Gain on sale of oil and natural gas properties	6,225	0	0
Other, net	43	358	0
Total other income (expense)	100,454	(45,118)	(17,774)
INCOME (LOSS) BEFORE INCOME TAX	231,933	(393,991)	(9,760)
Income tax expense (benefit)	66,475	57,943	0
NET INCOME (LOSS)	$ 165,458	$ (451,934)	(9,760)
Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share:
Basic (in dollars per share)	$ 0.78	$ (0.36)
Diluted (in dollars per share)	$ 0.78	$ (0.36)
Weighted average common shares outstanding:
Basic (in shares)	213,128	212,932
Diluted (in shares)	213,203	212,932
Predecessor
OTHER INCOME (EXPENSE)
NET INCOME (LOSS)	$ 0	$ (375,476)	(9,760)
Successor
OTHER INCOME (EXPENSE)
NET INCOME (LOSS)	165,458	(76,458)	0
Oil sales
REVENUES
Natural gas sales	539,802	241,788	70,078
Natural gas sales
REVENUES
Natural gas sales	9,136	9,065	2,213
NGL sales
REVENUES
Natural gas sales	31,956	15,571	3,068
Other operating revenues
REVENUES
Other operating revenues	$ 750	$ 888	$ 1,163

CONSOLIDATED AND COMBINED BAL_2

CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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	50,000,000
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	1,000,000,000
Common stock shares issued (in shares)	213,187,780	212,930,655

CONSOLIDATED AND COMBINED STA_2

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Equity-based compensation	$ 83,346	$ 442,976	$ 0

CONSOLIDATED AND COMBINED STA_3

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 165,458,000	$ (451,934,000)	$ (9,760,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	222,355,000	111,049,000	40,417,000
Management incentive unit advance	0	0	(14,712,000)
Impairment of unproved oil and natural gas properties	28,198,000	373,000	372,000
Exploratory dry hole costs	0	0	1,192,000
Amortization of debt issuance costs	2,340,000	606,000	260,000
Deferred income taxes	66,475,000	57,943,000	0
Equity-based compensation	83,346,000	442,976,000	0
(Gain) loss on commodity derivatives	(119,338,000)	42,615,000	15,145,000
Net cash receipts (payments) on settled derivatives	(34,134,000)	(2,618,000)	(2,292,000)
(Gain) on sale of oil and natural gas properties	(6,225,000)	0	0
Other	(314,000)	882,000	(160,000)
Change in operating assets and liabilities:
Accounts receivable and other current assets	(11,273,000)	(40,442,000)	(2,588,000)
Other assets	0	(3,000)	11,000
Accounts payable and accrued liabilities	30,768,000	17,424,000	4,198,000
Net cash provided by operating activities	427,656,000	178,871,000	32,083,000
CASH FLOWS FROM INVESTING ACTIVITIES
Leasehold and acquisition costs	(29,671,000)	(73,492,000)	(54,681,000)
Development of oil and natural gas properties	(706,689,000)	(523,559,000)	(139,571,000)
Other capital expenditures	(5,236,000)	(2,983,000)	(1,969,000)
Proceeds from sale of oil and natural gas properties	8,377,000	0	796,000
Net cash used in investing activities	(733,219,000)	(600,034,000)	(195,425,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from senior notes	500,000,000	0	0
Proceeds from issuance of common stock in initial public offering, net of underwriting fees	0	401,625,000	0
Proceeds from JPE LLC members	0	0	51,542,000
Proceeds from credit facility	165,000,000	165,000,000	112,000,000
Repayment of credit facility	(320,000,000)	(142,000,000)	0
Debt issuance costs	(13,531,000)	(2,362,000)	(1,220,000)
Costs relating to initial public offering	0	(3,216,000)	(1,418,000)
Employee tax withholding for settlement of equity compensation awards	(200,000)	(88,000)	0
Net cash provided by financing activities	331,269,000	418,959,000	160,904,000
NET CHANGE IN CASH AND CASH EQUIVALENTS	25,706,000	(2,204,000)	(2,438,000)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	9,523,000	11,727,000	14,165,000
CASH AND CASH EQUIVALENTS, END OF PERIOD	35,229,000	9,523,000	11,727,000
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest	23,157,000	2,021,000	2,190,000
Cash paid for income taxes	0	0	0
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	106,674,000	105,401,000	36,581,000
Asset retirement obligations	1,035,000	600,000	(100,000)
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Accrued offering costs	$ 0	$ 0	$ 1,224,000

CONSOLIDATED AND COMBINED STA_4

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Members' Equity	Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)
Beginning 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) | Successor	0
Net income (loss)	(9,760)
Ending Balance (Predecessor) at Dec. 31, 2016	326,112	346,098			(19,986)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) | Predecessor	(375,476)				(375,476)
Ending Balance (Predecessor) at Jan. 26, 2017	314,950	710,412			(395,462)
Beginning Balance (Predecessor) at Dec. 31, 2016	326,112	346,098			(19,986)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Capital contributions | Predecessor	364,314	364,314
Net income (loss) | Predecessor	(375,476)
Net income (loss) | Successor	(76,458)				(76,458)
Net income (loss)	(451,934)
Ending Balance (Predecessor) at Dec. 31, 2017		0
Ending Balance at Dec. 31, 2017	699,345		$ 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			(395,462)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock in corporate reorganization (in shares)			184,605
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	1,846	(710,412)		313,104	395,462
Issuance of common stock in initial public offering, net of offering costs (in shares)			28,333
Issuance of common stock in initial public offering, net of offering costs	396,991		$ 283	396,708
Equity-based compensation	63,950			63,950
Vested stock exchanged for tax withholding	(88)		(7)	(88)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	(199)				0
Net income (loss)	(76,458)
Ending Balance (Predecessor) at Dec. 31, 2017		0
Ending Balance at Dec. 31, 2017	699,345		$ 2,129	773,674	(76,458)
Ending Balance (in shares) at Dec. 31, 2017			212,931
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Equity-based compensation	83,346			83,346
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		0	$ 3	(202)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)			257
Net income (loss) | Predecessor	0
Net income (loss) | Successor	165,458
Net income (loss)	165,458				165,458
Ending Balance at Dec. 31, 2018	$ 947,950	$ 0	$ 2,132	$ 856,818	$ 89,000
Ending Balance (in shares) at Dec. 31, 2018			213,188

Organization, Operations and Ba

Organization, Operations and Basis of Presentation	12 Months Ended
	Dec. 31, 2018
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 former 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 offering 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 balances and transactions 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 5 and 7 , 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
	Dec. 31, 2018
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, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. 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 proved oil and natural gas properties, (2) accrued operating and capital costs, (3) estimates of timing and costs used in calculating asset retirement obligations, (4) estimates of the fair value of equity-based compensation, (5) assumptions and estimates used in the calculation of fair value, (6) estimates of deferred income taxes and (7) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in these estimates and assumptions could have a significant impact on results in future periods. Fair Value Measurements The Company’s financial instruments consist of derivative instruments, cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, the senior secured revolving credit facility and the Company’s 5.875% senior unsecured notes. The Company’s derivative instruments are measured at fair value on a recurring basis, while the senior secured revolving credit facility and the senior unsecured notes are not recorded at fair value on the consolidated and combined balance sheets. The carrying amounts of the Company’s other financial instruments are considered to be representative of their fair values due to the nature of and short-term maturities of those instruments. 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 9 , 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 On January 1, 2018, the Company adopted Accounting Standards Codification Topic 606, Revenue from Contracts with Customers , (“ASC 606”) using the modified retrospective approach, which only applied to contracts that were in effect as of the date of adoption. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and did not impact the Company’s previously reported results of operations, nor its ongoing consolidated and combined balance sheets, statements of cash flow or statements of changes in equity. Under ASC 606, oil, natural gas and NGL sales revenues are recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Company’s oil, natural gas and NGL sales are made under contracts with customers. The performance obligations for the Company’s contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery. The Company’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Under the Company’s current gas processing contracts, it delivers natural gas to a purchaser at or near the wellhead. For these contracts, the Company has concluded the purchaser is the customer, and as such, the Company recognizes natural gas and NGL revenues based on the net amount of proceeds it receives from the purchaser. The Company’s product types are as follows: Oil Sales . Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser at or near the wellhead, and collects a contractually agreed upon index price, net of pricing and gathering and transportation differentials. The Company transfers control of the product to the purchaser at or near the wellhead and recognizes revenue based on the net price received. Natural Gas and NGL Sales . Under the Company’s natural gas sales contracts, the Company delivers and transfers control of natural gas to the purchaser at delivery points at or near the wellhead. The purchaser gathers and processes the natural gas and sells the resulting residue gas and NGLs. The Company receives its contractual portion of the proceeds for the sale of the residue gas and NGLs at an agreed upon index price, net of pricing differentials and applicable selling expenses including gathering, processing and fractionation costs. The Company recognizes revenue at the net price when control transfers to the purchaser. The Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which the variable consideration is allocated entirely to a wholly unsatisfied performance obligation, as allowed under ASC 606. Under the Company’s oil, natural gas and NGL sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Disaggregation of Revenue The Company’s oil, natural gas and NGL sales revenues represent substantially all of its revenues, and are derived from the sale of oil, natural gas and NGL production within the Permian Basin. The Company believes the disaggregation of revenues into the three product types of oil sales, natural gas sales and NGL sales, as seen on the consolidated and combined statements of operations, is an appropriate level of detail for its primary activity. 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, 2018 and 2017 , 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, 2018 and 2017 , accounts receivable was comprised of the following: December 31, (in thousands) 2018 2017 Oil and gas sales $ 40,465 $ 42,869 Joint interest 14,058 7,860 Other 6,663 5 Total accounts receivable $ 61,186 $ 50,734 Significant Customers The Company’s share of oil, natural gas and NGL production relates to its operations in the southern Delaware Basin and 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, 2018 , 2017 and 2016 : Year Ended December 31, 2018 2017 2016 Trafigura Trading, LLC 85 % 78 % 57 % Sunoco Partners Marketing 2 % 11 % 31 % Other Current Assets The components of other current assets are shown below: December 31, (in thousands) 2018 2017 Prepaid expenses $ 1,626 $ 607 Other current assets 1 199 Total other current assets $ 1,627 $ 806 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 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) 2018 2017 Proved oil and natural gas properties $ 1,746,766 $ 1,012,321 Unproved oil and natural gas properties 158,732 183,510 Total oil and natural gas properties 1,905,498 1,195,831 Less: Accumulated depletion (386,883 ) (166,592 ) Total oil and natural gas properties, net $ 1,518,615 $ 1,029,239 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, 2018 , 2017 and 2016 , the Company recorded depletion for oil and natural gas properties of $220.3 million , $109.2 million and $39.4 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 9 , Fair Value Measurements . The Company did not record any impairment expense associated with its proved properties during the years ended December 31, 2018 , 2017 and 2016 . 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 $28.2 million , $0.4 million and $0.4 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Impairment of unproved oil and natural gas properties in 2018 primarily resulted from the Company’s ongoing evaluation of its undeveloped Big Tex acreage and the current plan to not drill on certain of these leases before they expire. There were no exploratory dry hole costs incurred in 2018 or 2017. However, during 2016 the Company incurred dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon. Impairments are presented within impairment of unproved oil and natural gas properties, while exploratory 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) 2018 2017 Other property and equipment $ 16,021 $ 12,167 Less: Accumulated depreciation (4,351 ) (2,459 ) Total other property and equipment, net $ 11,670 $ 9,708 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 3 to 30 years. Depreciation expense for the years ended December 31, 2018 , 2017 and 2016 was $1.9 million , $1.7 million and $0.9 million , respectively. When property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounting records. Accrued Liabilities The components of accrued liabilities are shown below: December 31, (in thousands) 2018 2017 Accrued capital expenditures $ 74,688 $ 102,956 Accrued accounts payable 5,941 8,488 Royalties payable 19,964 6,105 Other current liabilities 29,419 14,762 Total accrued liabilities $ 130,012 $ 132,311 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 nonemployee 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. 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 $0.7 million , $0.5 million and $0.2 million for each of the years ended December 31, 2018 , 2017 and 2016 , respectively. Benefits under this plan are available to all employees, and employees are fully vested in the employer contribution upon receipt. Recent Accounting Pronouncements Recently Adopted Accounting Standards Revenue from Contracts with Customers . In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which outlined a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most prior revenue recognition guidance, including industry-specific guidance. The Company adopted the new standard on January 1, 2018, as described above. The Company implemented the necessary changes to its business processes, systems and controls to support recognition and disclosure of this new standard. The Company’s financial statement presentation related to revenue received from certain gas sales contracts changed as a result of the new standard. Under previous guidance, proceeds from certain gas sales contracts were reported gross, with related costs for gathering and processing being presented separately as gathering and processing expense. Upon adoption of the new standard, the Company presents revenue from these contracts net of gathering and processing costs, as these costs are incurred after control of the product is transferred to the customer. The impact of the new revenue recognition standard on the Company’s current period results is as follows: Year Ended December 31, 2018 (in thousands) Amounts presented on statements of operations ASC 606 Adjustments Previous Revenue Recognition Method Revenues Oil sales $ 539,802 $ — $ 539,802 Natural gas sales 9,136 3,488 12,624 NGL sales 31,956 11,243 43,199 Other operating revenues 750 — 750 Total revenues $ 581,644 $ 14,731 $ 596,375 Operating expenses Gathering and processing expenses $ — $ 14,731 $ 14,731 Net income (loss) $ 165,458 $ — $ 165,458 Adoption of the new standard did not impact the Company’s previously reported results of operations or consolidated and combined cash flows statements. Stock Compensation - Scope of Modification Accounting . In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting . The ASU clarified 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 adoption of this new standard did not impact the Company’s consolidated and combined balance sheets, statements of operations or statements of cash flows. Accounting Standards Not Yet Adopted Leases . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires entities to determine at the inception of a contract if the contract is, or contains, a lease. Entities are then required to recognize leases as right-of-use assets and lease payment liabilities on the balance sheet as well as disclose key information about leasing arrangements. The new standard is effective for the Company on January 1, 2019. Entities are permitted to make a policy election under ASU 2016-02 to not recognize lease assets or liabilities when the term of the lease is less than twelve months. For agreements that contain both lease and non-lease components, entities are also permitted to make a policy election to combine both the lease and non-lease components together and account for these arrangements as a single lease. The update does not apply to leases of mineral rights to explore for or use oil and natural gas. ASU 2016-02 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. Under ASU 2016-02, entities are required to adopt the new standard using a modified retrospective approach and apply the provisions of ASU 2016-02 to leasing arrangements existing at, or entered into, after the earliest comparative period presented in the financial statements. 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. In July 2018, the FASB issued ASU 2018-11, Targeted Improvements , which provides entities an optional transitional relief method whereby prior periods would not require restatement while a cumulative adjustment to retained earnings during the period of adoption would be recorded. The Company will adopt ASU 2016-02, as amended, using a modified retrospective approach as permitted under ASU 2018-11, which allows the Company to apply the legacy lease guidance and disclosure requirements in the comparative periods presented for the year of adoption. No cumulative-effect adjustment to retained earnings is expected to be recognized upon adoption of ASU 2016-02. As part of the adoption, the Company elected the short-term lease recognition policy election for all leases that qualify, and as such, no right-of-use assets or lease payment liabilities will be recorded on the balance sheet when the term of the lease is less than twelve months. The Company also elected the practical expedient under ASC 2018-01 pertaining to land easements, that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. The implementation of this standard will impact the Company’s current processes and controls, including contract identification and assessment. Additionally, the Company is currently finalizing the implementation of a lease administration software that will support the accounting and disclosure for leases. Adopting ASU 2016-02 will result in increases to long-term assets, current liabilities and long-term liabilities on its consolidated and combined balance sheets, related to the recognition of new right-of-use assets and lease liabilities, and will require additional disclosures of key information related to its leases in the footnotes to the financial statements. The Company is finalizing its implementation of ASU 2016-02, as amended, and has identified long-term leases for certain asset classes, including drilling rigs, corporate office space and certain office equipment. As of December 31, 2018 , the Company’s undiscounted obligations for operating leases and drilling rigs in the Company’s contractual obligations table totaled approximately $83.9 million (see Note 10 , Commitments and Contingencies , for additional information). Financial Instruments: Credit Losses . In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , which replaces the currently required incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2020, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have been de minimis, and the Company does not believe the adoption of 2016-13 will have a material impact on its consolidated and combined financial statements.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2018
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 using Level 2 inputs. 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 9 , 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 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, 2018 : Contract Period Volumes Wtd Avg Price Oil Swaps: (1) First quarter 2019 1,890,000 $ 59.95 Second quarter 2019 1,911,000 $ 59.95 Third quarter 2019 1,932,000 $ 59.95 Fourth quarter 2019 1,932,000 $ 59.95 Total 2019 7,665,000 $ 59.95 Year ending December 31, 2020 2,928,000 $ 60.82 Oil Basis Swaps: (2) First quarter 2019 2,070,000 $ (7.17 ) Second quarter 2019 2,093,000 $ (7.17 ) Third quarter 2019 2,300,000 $ (4.79 ) Fourth quarter 2019 2,300,000 $ (4.79 ) Total 2019 8,763,000 $ (5.92 ) Year ending December 31, 2020 9,516,000 $ (1.31 ) (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. Accordingly, the changes in fair value of these instruments are recognized through current earnings as other income or expense as they occur. 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. The following table sets forth the components of gain (loss) on commodity derivatives for the years ended December 31, 2018 , 2017 and 2016 : (in thousands) 2018 2017 2016 Net cash receipts (payments) on settled derivatives $ (34,134 ) $ (2,618 ) $ (2,292 ) Gain (loss) from the change in fair value of open derivative contracts, net 153,472 (39,997 ) (12,853 ) Gain (loss) on commodity derivatives $ 119,338 $ (42,615 ) $ (15,145 ) The Company’s derivative contracts are carried at their fair value on the Company’s consolidated and combined balance sheets, 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, 2018 and 2017 (in thousands): As of December 31, 2018: 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 $ 103,092 $ (18,815 ) $ 84,277 Commodity contracts Noncurrent assets - derivative instruments 31,899 (9,668 ) 22,231 Total assets $ 134,991 $ (28,483 ) $ 106,508 Liabilities Commodity contracts Current liabilities - derivative instruments $ 23,208 $ (18,815 ) $ 4,393 Commodity contracts Noncurrent liabilities - derivative instruments 11,162 (9,668 ) 1,494 Total liabilities $ 34,370 $ (28,483 ) $ 5,887 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 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 comprises 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, 2018 , the Company had commodity derivative contracts with six counterparties, all of which were lenders under the Company’s Amended and Restated Credit Facility (as defined in Note 4 , Debt ) 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.

Debt

Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt	Debt The Company’s debt consisted of the following at December 31, 2018 and December 31, 2017 : (in thousands) December 31, 2018 December 31, 2017 Senior secured revolving credit facility $ — $ 155,000 5.875% senior unsecured notes due 2026 500,000 — Debt issuance costs on senior unsecured notes (10,761 ) — Total long-term debt $ 489,239 $ 155,000 Senior Secured Revolving Credit Facility In June 2015, the Company entered into a five -year senior secured revolving credit facility. At December 31, 2017 , the credit facility, as amended (the “Amended and Restated Credit Facility”), had a borrowing base of $425.0 million , with $155.0 million outstanding under the credit facility, and $270.0 million in unused borrowing capacity. The weighted average interest rate as of December 31, 2017 was 3.68% . During the year ended December 31, 2017 , JPE LLC 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 21, 2023 and increased the borrowing base to $540.0 million . Borrowings under the Amended and Restated Credit Facility under Amendment No. 2 bear interest at a rate elected by the Company that is equal to an adjusted 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 adjusted 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 elected commitments. The Company also incurs a commitment fee that is between 0.375% to 0.50% per year on the unused portion of the elected commitments, depending on the relative amount of the loan outstanding in relation to the elected commitments. In April 2018, and in connection with the issuance of the Senior Notes (as described and defined below), the lenders of the Amended and Restated Credit Facility agreed to waive a provision that would require a borrowing base reduction as a result of the Senior Notes. As a result, the borrowing base of the Amended and Restated Credit Facility continued to be $540.0 million . The Company also voluntarily elected to reduce the elected commitments to $475.0 million , effective as of the closing of the Senior Notes offering. Additionally, a portion of the proceeds from the Senior Notes were used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received. In June 2018, the Company entered into Amendment No. 3 to the Amended and Restated Credit Facility which increased the amount of production volumes the Company is permitted to hedge up to 85% of forecasted future production for up to 36 months in the future, and up to the greater of 75% of production from its proved reserves and 60% of its reasonably anticipated forecasted production for 37 to 60 months in the future, provided that no hedges have a term beyond five years. In August 2018, the Company entered into Amendment No. 4 to the Amended and Restated Credit Facility, which increased the borrowing base to $825.0 million , and the Company increased its elected commitments to $540.0 million . In November 2018, the Company entered into Amendment No. 5 to the Amended and Restated Credit Facility, which increased the borrowing base to $900.0 million while the elected commitments remained at $540.0 million . The Amended and Restated Credit Facility is secured by oil and natural gas properties representing at least 90% of the value of the Company’s proved reserves. The Amended and Restated Credit Facility contains certain nonfinancial covenants, including among others, restrictions on indebtedness, liens, investments, mergers, sales of assets, hedging activity, and dividends and payments to the Company’s capital interest holders. The Amended and Restated Credit Facility also contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Facility, 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, 2018 , the Company was in compliance with its financial covenants. As of December 31, 2018 , there were no outstanding amounts under the Amended and Restated Credit Facility, and $540.0 million of elected commitments available. During the year ended December 31, 2018 , the Company capitalized $1.2 million of interest. 5.875% Senior Unsecured Notes due 2026 On May 8, 2018, JPE LLC issued $500.0 million aggregate principal amount of 5.875% senior unsecured notes that mature on May 1, 2026 (the “Senior Notes”) in a 144A private placement that was exempt from registration under the Securities Act. Interest is payable on the Senior Notes semi-annually in arrears on each May 1 and November 1, which commenced on November 1, 2018. The Senior Notes resulted in net proceeds to the Company of $488.3 million , net of offering expenses. A portion of such proceeds was used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received. The remainder of the net proceeds were used to fund a portion of the Company’s 2018 capital program and for other general corporate purposes. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by Jagged Peak and may be guaranteed by future subsidiaries. Jagged Peak has no independent assets or operations and has no other subsidiaries other than JPE LLC. There are no significant restrictions on the Company’s ability to obtain funds from its subsidiary in the form of cash dividends or other distributions of funds. In connection with the issuance of the Senior Notes, the Company entered into a registration rights agreement with the initial purchasers, dated May 8, 2018, to allow holders of the unregistered Senior Notes to exchange the unregistered Senior Notes for registered notes that have substantially identical terms. On December 13, 2018, the Company filed a registration statement on Form S-4 (the “S-4 Registration Statement”) with the SEC with respect to an offer to exchange the Senior Notes for registered, publicly tradable notes that have terms identical in all material respects to the Senior Notes (except that the exchange notes do not contain any transfer restrictions) (the “Exchange Offer”). On January 31, 2019, the Company filed Amendment No. 1 to the S-4 Registration Statement with respect to the Exchange Offer. On February 5, 2019, the S-4 Registration was declared effective by the SEC and the Company commenced the Exchange Offer. The Exchange Offer is expected to close in the first quarter of 2019. If the Company experiences certain defined changes of control, each holder of the Senior Notes may require the Company to repurchase all or a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes plus accrued and unpaid interest as of the date of repurchase, if any. The indenture governing the Senior Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

Equity-based Compensation

Equity-based Compensation	12 Months Ended
	Dec. 31, 2018
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) 2018 2017 2016 Incentive unit awards $ 76,442 $ 439,411 $ — Restricted stock unit awards 3,873 1,616 — Performance stock unit awards 2,530 1,497 — Restricted stock unit awards issued to nonemployee directors 501 452 — Total equity-based compensation expense $ 83,346 $ 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. The shares of common stock transferred to Management Holdco are accounted for under ASC 718, Compensation–Stock Compensation , and generally vest over three years, beginning at the date of allocation. During the year ended December 31, 2018 , the Company recognized $76.4 million of equity-based compensation expense related to the shares held by Management Holdco, which included $71.3 million of equity-based compensation related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO (as described further below). For the year ended December 31, 2017 , equity-based compensation expense of $443.0 million included (1) $379.0 million related to 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, and (2) $22.2 million related to a modification 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. 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 would be 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 should be 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 the 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 resulted in the recognition of approximately $71.3 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. A summary of incentive unit award activity for the year ended December 31, 2018 is as follows: Weighted Average Grant-date Incentive Units Fair Value Unvested at December 31, 2017 7,755,745 $ 14.93 Granted 504,628 $ 13.21 Vested (2,789,511 ) $ 14.95 Forfeited (73,307 ) $ 12.21 Unvested at December 31, 2018 5,397,555 $ 14.79 Compensation costs remaining at December 31, 2018 (in millions) $ 5.7 Weighted average remaining period at December 31, 2018 (in years) 2.3 The weighted average grant-date fair value of incentive units was $13.21 in 2018 and $12.45 in 2017 . No incentive units were granted prior to the corporate reorganization. The total fair value of incentive units that vested according to the legal service obligations during the year ended December 31, 2018 was $35.4 million , and the fair value that vested from the IPO date to December 31, 2017 was $25.2 million . At December 31, 2018 , there were no remaining unallocated shares of Company common stock held at Management Holdco. 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, 2018 is as follows: Weighted Average Grant-date RSUs Fair Value Unvested at December 31, 2017 582,973 $ 12.44 Granted 716,734 $ 12.57 Vested (272,678 ) $ 12.40 Forfeited (155,910 ) $ 12.51 Unvested at December 31, 2018 871,119 $ 12.55 Compensation costs remaining at December 31, 2018 (in millions) $ 7.9 Weighted average remaining period at December 31, 2018 (in years) 2.1 The weighted average grant-date fair value of RSUs was $12.57 in 2018 and $12.45 in 2017 . No RSUs were granted prior to 2017. The total fair value of RSUs that vested during the year ended December 31, 2018 was $3.4 million , while no RSUs vested prior to 2018 . Of the 716,734 RSUs granted during 2018 , nonemployee directors received 30,753 at a weighted average grant-date fair value of $13.17 . The remaining compensation costs at December 31, 2018 for these nonemployee director RSUs was $0.1 million , with a weighted average remaining period of 0.3 years. Performance Stock Unit Awards The Company grants 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. 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, 2018 is as follows: Weighted Average Grant-date PSUs Fair Value Unvested at December 31, 2017 398,566 $ 16.32 Granted 546,319 $ 16.23 Vested — $ — Forfeited (253,522 ) $ 16.32 Unvested at December 31, 2018 691,363 $ 16.25 Compensation costs remaining at December 31, 2018 (in millions) $ 7.2 Weighted average remaining period at December 31, 2018 (in years) 1.9 The weighted average grant-date fair value of PSUs was $16.23 in 2018 and $16.32 in 2017 . No PSUs were granted prior to 2017 and no PSUs vested in 2018 or 2017 . 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 three -year performance period for the PSUs granted during the years ended December 31, 2018 and 2017 ends December 31, 2020 and December 31, 2019, respectively. The following table presents information regarding the weighted average fair value for the PSUs granted in 2018 and 2017 , including the assumptions used to determine the fair values: Years Ended December 31, 2018 2017 Dividend yield — % — % Volatility 37.3 % 55.7 % Risk-free interest rate 2.34 % 1.34 %

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2018
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: Year Ended From January 27, 2017, to (in thousands, except per share amounts) December 31, 2018 December 31, 2017 Net income (loss) attributable to Jagged Peak Energy Inc. stockholders $ 165,458 $ (76,458 ) Basic weighted average shares outstanding 213,128 212,932 Dilutive restricted stock units 75 — Dilutive performance stock units — — Diluted weighted average shares outstanding 213,203 212,932 Net income (loss) per common share: Basic $ 0.78 $ (0.36 ) Diluted $ 0.78 $ (0.36 ) The following table presents the weighted average number of outstanding equity awards that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive: Year Ended From January 27, 2017, to (in thousands) December 31, 2018 December 31, 2017 Number of antidilutive units: (1) Antidilutive restricted stock units 217 411 Antidilutive performance stock units 585 523 (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 antidilutive.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
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 were made for the operations of the Company following January 27, 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 reduced the U.S. corporate income tax rate to 21%, (ii) repealed the corporate alternative minimum tax, (iii) imposed new limitations on the utilization of net operating losses and eliminated their carryforward restrictions and (iv) provided 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 preserved deductibility of intangible drilling costs and provided 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 SEC issued rules that allowed 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's accounting for the effects of the tax rate change on its deferred tax balances as well as other relevant aspects of the Tax Act was completed as of December 31, 2017 and no provisional amounts were recorded at year-end 2017 that were later adjusted in 2018. Future interpretations relating to the passage of the Tax Act which vary from the Company’s current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on the Company’s future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted. The components of the Company’s provision for income taxes are as follows: Year Ended December 31, (in thousands) 2018 2017 Current income tax expense: Federal $ — $ — State — — — — Deferred income tax expense: Federal 64,364 56,350 State 2,111 1,593 66,475 57,943 Provision for income taxes $ 66,475 $ 57,943 A reconciliation of the income tax expense calculated at the federal statutory rate to the total income tax expense is as follows: Year Ended December 31, (in thousands) 2018 2017 Income (loss) before income taxes $ 231,933 $ (393,991 ) Less: loss before income taxes prior to corporate reorganization — (375,476 ) Income (loss) before income taxes subsequent to corporate reorganization $ 231,933 $ (18,515 ) Income tax expense (benefit) at the federal statutory rate $ 48,706 $ (6,480 ) Nondeductible equity-based compensation (1) 15,614 20,781 State income taxes, net of federal benefit 2,111 199 Other permanent differences 44 21 Income tax expense relating to change in tax status — 80,704 Federal tax reform changes - the Tax Act (2) — (37,282 ) Income tax expense (benefit) $ 66,475 $ 57,943 Effective tax rate 28.7 % (14.7 )% (1) 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 5 , Equity-based Compensation , for more information on the shares of common stock transferred to Management Holdco. (2) The Tax Act reduced the U.S. federal statutory rate from 35% to 21% beginning in 2018. Prior to the Company’s change in tax status in January 2017, income taxes did not significantly impact the results of operations. The components of the Company’s deferred income tax assets and liabilities are as follows: (in thousands) December 31, 2018 December 31, 2017 Deferred income tax assets: Commodity derivatives $ — $ 11,412 Equity-based compensation 1,963 928 Net operating loss carryforwards 19,788 16,093 Other 3,026 1,726 24,777 30,159 Deferred income tax liabilities: Oil and natural gas properties 127,468 88,102 Commodity derivatives 21,727 — 149,195 88,102 Net deferred income tax assets (liabilities) $ (124,418 ) $ (57,943 ) The Company had U.S. net operating losses of approximately $94.2 million , of which approximately $75.5 million expire in 2037 and $18.8 million are limited to 80% of taxable income per year and will not expire. 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, 2018 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, 2018 , 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, 2018 , 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 2015 through 2017 , and its Texas and Colorado tax returns remain open to examination for the years 2014 through 2017 .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 . Any ARO classified as current is included in accrued liabilities on the consolidated and combined balance sheets. (in thousands) 2018 2017 Asset retirement obligations at January 1, $ 929 $ 448 Liabilities incurred and assumed 718 590 Liability settlements and disposals (33 ) (190 ) Revisions of estimated liabilities 335 9 Accretion 123 72 Asset retirement obligations at December 31, 2,072 929 Less current portion of asset retirement obligations (126 ) (118 ) Long-term asset retirement obligations $ 1,946 $ 811 In 2018 and 2017 , the Company recognized revisions of estimated liabilities totaling $0.3 million and $9 thousand , respectively, which were due to changes in estimated abandonment timing and costs.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
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). Certain financial assets and liabilities, such as derivative instruments, 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. Reclassifications of fair value among Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers among Level 1, Level 2 or Level 3 during the year ended December 31, 2018 . Assets and liabilities measured on a recurring basis Certain assets and liabilities are reported at fair value on a recurring basis. The following table sets forth the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis: Level 2 (in thousands) December 31, 2018 December 31, 2017 Assets from commodity derivative contracts $ 134,991 $ 26 Liabilities due to commodity derivative contracts $ 34,370 $ 52,877 The fair value of the Company’s oil swaps and basis swaps is computed using 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. Fair Value of Other Financial Instruments The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated and combined balance sheets: December 31, 2018 December 31, 2017 (in thousands) Principal Amount Fair Value Carrying Amount Fair Value Long-term debt: Senior secured revolving credit facility $ — $ — $ 155,000 $ 155,000 5.875% senior unsecured notes due 2026 $ 500,000 $ 466,250 $ — $ — The fair value of the Amended and Restated Credit Facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes at December 31, 2018 was based on the quoted market price and is classified as Level 1 in the fair value hierarchy. The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are considered to be representative of their respective fair values due to the nature of and short-term maturities of those instruments. Assets and liabilities measured on a nonrecurring basis Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. These assets and liabilities include the acquisition or impairment of proved and unproved oil and gas properties and the inception value of asset retirement obligation liabilities. Proved oil and natural gas properties . 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. Unproved oil and natural gas properties . 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. These assumptions and estimates represent Level 3 inputs. The following table sets forth the noncash impairments of both proved and unproved properties for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 2016 Proved oil and natural gas property impairments $ — $ — $ — Unproved oil and natural gas property impairments (1) 28,198 373 372 $ 28,198 $ 373 $ 372 (1) Impairment of unproved oil and natural gas properties in 2018 primarily resulted from the Company’s ongoing evaluation of its undeveloped Big Tex acreage and the current plan to not drill on certain of these leases before they expire. Impairment of unproved oil and natural gas properties in 2017 and 2016 resulted from expirations of certain undeveloped leases. Asset retirement obligations . The inception value and new layers resulting from upward revisions of the Company’s ARO liabilities 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
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, 2018 : (in thousands) 2019 2020 2021 2022 2023 Thereafter Total Operating leases $ 1,547 $ 1,539 $ 1,553 $ 1,559 $ 1,589 $ 7,378 $ 15,165 Service and purchase contracts (1) 7,598 1,285 750 — — — 9,633 Rig contracts 36,805 31,897 — — — — 68,702 Frac fleet contracts 63,135 — — — — — 63,135 Total $ 109,085 $ 34,721 $ 2,303 $ 1,559 $ 1,589 $ 7,378 $ 156,635 (1) Primarily relates to a retail power purchase agreement. Operating lease commitments The Company leases office space in Denver, Colorado. The Company’s 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 $2.3 million , $0.9 million , and $0.6 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Drilling rig commitments At December 31, 2018 , the Company had seven operated drilling rigs running. If the Company were to terminate all of its drilling rig contracts at December 31, 2018 , it would be required to pay early termination penalties of $37.7 million . In January 2019, two of the seven rigs were released, which resulted in early termination penalties of $0.3 million . Of these two rigs that were released, one was on a well-to-well contract, while the other was contractually obligated through August 2019. Included in the commitments table above is $0.3 million that represents the obligations for these two rigs to finish the wells they were drilling as of December 31, 2018 . Frac fleet commitments At December 31, 2018 , the Company had two frac fleets under contract through December 31, 2019. In the first quarter of 2019 the Company terminated one of the frac fleet contracts. As a result, the Company paid a termination fee of $3.2 million in 2019. The remaining frac fleet under contract at December 31, 2018 does not contain early termination fees. Minimum volume commitments In November 2018, the Company entered into a 5 -year oil marketing agreement that is expected to take effect at the commencement of commercial operations on the Cactus II pipeline and will link a portion of the Company’s oil production to Gulf Coast pricing. This agreement specifies a minimum gross volume commitment of 30,000 barrels of oil per day. If the Company is not able to provide the contractual quantity to the buyer, it would be subject to a deficiency payment relative to a price difference on the deficient volume. Based on its current and projected production levels, the Company does not believe a deficiency payment will be required under this agreement. 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, 2018 and 2017 , 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
	Dec. 31, 2018
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, 2018 , Quantum owns 68.6% 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 62.0% 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) 2018 2017 2016 Oryx via 3rd party shipper (1) $ 23,239 $ 10,058 $ 2,125 Oryx (2) $ 894 $ 798 $ 1,765 Phoenix (3) $ 364 $ 366 $ 338 Trident (3) $ 464 $ 236 $ 590 (1) Fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil transportation and 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 metering 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, 2018 and 2017 , the Company had outstanding payables to these related parties of $2.6 million and $1.8 million , respectively.

Significant Accounting Polici_2

Significant Accounting Policies and Related Matters (Policies)	12 Months Ended
	Dec. 31, 2018
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 balances and transactions 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 5 and 7 , respectively.
Reclassification	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, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. 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 proved oil and natural gas properties, (2) accrued operating and capital costs, (3) estimates of timing and costs used in calculating asset retirement obligations, (4) estimates of the fair value of equity-based compensation, (5) assumptions and estimates used in the calculation of fair value, (6) estimates of deferred income taxes and (7) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in these estimates and assumptions could have a significant impact on results in future periods.
Fair Value Measurements	Fair Value Measurements The Company’s financial instruments consist of derivative instruments, cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, the senior secured revolving credit facility and the Company’s 5.875% senior unsecured notes. The Company’s derivative instruments are measured at fair value on a recurring basis, while the senior secured revolving credit facility and the senior unsecured notes are not recorded at fair value on the consolidated and combined balance sheets. The carrying amounts of the Company’s other financial instruments are considered to be representative of their fair values due to the nature of and short-term maturities of those instruments. 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 9 , 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 On January 1, 2018, the Company adopted Accounting Standards Codification Topic 606, Revenue from Contracts with Customers , (“ASC 606”) using the modified retrospective approach, which only applied to contracts that were in effect as of the date of adoption. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and did not impact the Company’s previously reported results of operations, nor its ongoing consolidated and combined balance sheets, statements of cash flow or statements of changes in equity. Under ASC 606, oil, natural gas and NGL sales revenues are recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Company’s oil, natural gas and NGL sales are made under contracts with customers. The performance obligations for the Company’s contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery. The Company’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. Under the Company’s current gas processing contracts, it delivers natural gas to a purchaser at or near the wellhead. For these contracts, the Company has concluded the purchaser is the customer, and as such, the Company recognizes natural gas and NGL revenues based on the net amount of proceeds it receives from the purchaser. The Company’s product types are as follows: Oil Sales . Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser at or near the wellhead, and collects a contractually agreed upon index price, net of pricing and gathering and transportation differentials. The Company transfers control of the product to the purchaser at or near the wellhead and recognizes revenue based on the net price received. Natural Gas and NGL Sales . Under the Company’s natural gas sales contracts, the Company delivers and transfers control of natural gas to the purchaser at delivery points at or near the wellhead. The purchaser gathers and processes the natural gas and sells the resulting residue gas and NGLs. The Company receives its contractual portion of the proceeds for the sale of the residue gas and NGLs at an agreed upon index price, net of pricing differentials and applicable selling expenses including gathering, processing and fractionation costs. The Company recognizes revenue at the net price when control transfers to the purchaser. The Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which the variable consideration is allocated entirely to a wholly unsatisfied performance obligation, as allowed under ASC 606. Under the Company’s oil, natural gas and NGL sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Disaggregation of Revenue The Company’s oil, natural gas and NGL sales revenues represent substantially all of its revenues, and are derived from the sale of oil, natural gas and NGL production within the Permian Basin. The Company believes the disaggregation of revenues into the three product types of oil sales, natural gas sales and NGL sales, as seen on the consolidated and combined statements of operations, is an appropriate level of detail for its primary activity.
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 relates to its operations in the southern Delaware Basin and 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.
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 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, 2018 , 2017 and 2016 , the Company recorded depletion for oil and natural gas properties of $220.3 million , $109.2 million and $39.4 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 9 , Fair Value Measurements . The Company did not record any impairment expense associated with its proved properties during the years ended December 31, 2018 , 2017 and 2016 . 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 $28.2 million , $0.4 million and $0.4 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Impairment of unproved oil and natural gas properties in 2018 primarily resulted from the Company’s ongoing evaluation of its undeveloped Big Tex acreage and the current plan to not drill on certain of these leases before they expire. There were no exploratory dry hole costs incurred in 2018 or 2017. However, during 2016 the Company incurred dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon. Impairments are presented within impairment of unproved oil and natural gas properties, while exploratory 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 The following table presents the components of other property and equipment, net: December 31, (in thousands) 2018 2017 Other property and equipment $ 16,021 $ 12,167 Less: Accumulated depreciation (4,351 ) (2,459 ) Total other property and equipment, net $ 11,670 $ 9,708 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 3 to 30 years. Depreciation expense for the years ended December 31, 2018 , 2017 and 2016 was $1.9 million , $1.7 million and $0.9 million , respectively. When property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounting records.
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.
Equity-based Compensation	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 nonemployee 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.
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. 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	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 $0.7 million , $0.5 million and $0.2 million for each of the years ended December 31, 2018 , 2017 and 2016 , respectively. 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 Recently Adopted Accounting Standards Revenue from Contracts with Customers . In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which outlined a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most prior revenue recognition guidance, including industry-specific guidance. The Company adopted the new standard on January 1, 2018, as described above. The Company implemented the necessary changes to its business processes, systems and controls to support recognition and disclosure of this new standard. The Company’s financial statement presentation related to revenue received from certain gas sales contracts changed as a result of the new standard. Under previous guidance, proceeds from certain gas sales contracts were reported gross, with related costs for gathering and processing being presented separately as gathering and processing expense. Upon adoption of the new standard, the Company presents revenue from these contracts net of gathering and processing costs, as these costs are incurred after control of the product is transferred to the customer. The impact of the new revenue recognition standard on the Company’s current period results is as follows: Year Ended December 31, 2018 (in thousands) Amounts presented on statements of operations ASC 606 Adjustments Previous Revenue Recognition Method Revenues Oil sales $ 539,802 $ — $ 539,802 Natural gas sales 9,136 3,488 12,624 NGL sales 31,956 11,243 43,199 Other operating revenues 750 — 750 Total revenues $ 581,644 $ 14,731 $ 596,375 Operating expenses Gathering and processing expenses $ — $ 14,731 $ 14,731 Net income (loss) $ 165,458 $ — $ 165,458 Adoption of the new standard did not impact the Company’s previously reported results of operations or consolidated and combined cash flows statements. Stock Compensation - Scope of Modification Accounting . In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting . The ASU clarified 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 adoption of this new standard did not impact the Company’s consolidated and combined balance sheets, statements of operations or statements of cash flows. Accounting Standards Not Yet Adopted Leases . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires entities to determine at the inception of a contract if the contract is, or contains, a lease. Entities are then required to recognize leases as right-of-use assets and lease payment liabilities on the balance sheet as well as disclose key information about leasing arrangements. The new standard is effective for the Company on January 1, 2019. Entities are permitted to make a policy election under ASU 2016-02 to not recognize lease assets or liabilities when the term of the lease is less than twelve months. For agreements that contain both lease and non-lease components, entities are also permitted to make a policy election to combine both the lease and non-lease components together and account for these arrangements as a single lease. The update does not apply to leases of mineral rights to explore for or use oil and natural gas. ASU 2016-02 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. Under ASU 2016-02, entities are required to adopt the new standard using a modified retrospective approach and apply the provisions of ASU 2016-02 to leasing arrangements existing at, or entered into, after the earliest comparative period presented in the financial statements. 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. In July 2018, the FASB issued ASU 2018-11, Targeted Improvements , which provides entities an optional transitional relief method whereby prior periods would not require restatement while a cumulative adjustment to retained earnings during the period of adoption would be recorded.

Significant Accounting Polici_3

Significant Accounting Policies and Related Matters (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of Accounts Receivable	At December 31, 2018 and 2017 , accounts receivable was comprised of the following: December 31, (in thousands) 2018 2017 Oil and gas sales $ 40,465 $ 42,869 Joint interest 14,058 7,860 Other 6,663 5 Total accounts receivable $ 61,186 $ 50,734
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, 2018 , 2017 and 2016 : Year Ended December 31, 2018 2017 2016 Trafigura Trading, LLC 85 % 78 % 57 % Sunoco Partners Marketing 2 % 11 % 31 %
Schedule of Other Current Assets	The components of other current assets are shown below: December 31, (in thousands) 2018 2017 Prepaid expenses $ 1,626 $ 607 Other current assets 1 199 Total other current assets $ 1,627 $ 806
Oil, Natural Gas Properties, Property, Plant and Equipment	A summary of the Company’s oil and natural gas properties, net is as follows: December 31, (in thousands) 2018 2017 Proved oil and natural gas properties $ 1,746,766 $ 1,012,321 Unproved oil and natural gas properties 158,732 183,510 Total oil and natural gas properties 1,905,498 1,195,831 Less: Accumulated depletion (386,883 ) (166,592 ) Total oil and natural gas properties, net $ 1,518,615 $ 1,029,239 The following table presents the components of other property and equipment, net: December 31, (in thousands) 2018 2017 Other property and equipment $ 16,021 $ 12,167 Less: Accumulated depreciation (4,351 ) (2,459 ) Total other property and equipment, net $ 11,670 $ 9,708
Schedule of Accrued Liabilities	The components of accrued liabilities are shown below: December 31, (in thousands) 2018 2017 Accrued capital expenditures $ 74,688 $ 102,956 Accrued accounts payable 5,941 8,488 Royalties payable 19,964 6,105 Other current liabilities 29,419 14,762 Total accrued liabilities $ 130,012 $ 132,311
Impact of New Revenue Recognition Standard	The impact of the new revenue recognition standard on the Company’s current period results is as follows: Year Ended December 31, 2018 (in thousands) Amounts presented on statements of operations ASC 606 Adjustments Previous Revenue Recognition Method Revenues Oil sales $ 539,802 $ — $ 539,802 Natural gas sales 9,136 3,488 12,624 NGL sales 31,956 11,243 43,199 Other operating revenues 750 — 750 Total revenues $ 581,644 $ 14,731 $ 596,375 Operating expenses Gathering and processing expenses $ — $ 14,731 $ 14,731 Net income (loss) $ 165,458 $ — $ 165,458

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following table summarizes the Company’s derivative contracts as of December 31, 2018 : Contract Period Volumes Wtd Avg Price Oil Swaps: (1) First quarter 2019 1,890,000 $ 59.95 Second quarter 2019 1,911,000 $ 59.95 Third quarter 2019 1,932,000 $ 59.95 Fourth quarter 2019 1,932,000 $ 59.95 Total 2019 7,665,000 $ 59.95 Year ending December 31, 2020 2,928,000 $ 60.82 Oil Basis Swaps: (2) First quarter 2019 2,070,000 $ (7.17 ) Second quarter 2019 2,093,000 $ (7.17 ) Third quarter 2019 2,300,000 $ (4.79 ) Fourth quarter 2019 2,300,000 $ (4.79 ) Total 2019 8,763,000 $ (5.92 ) Year ending December 31, 2020 9,516,000 $ (1.31 ) (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 following table sets forth the components of gain (loss) on commodity derivatives for the years ended December 31, 2018 , 2017 and 2016 : (in thousands) 2018 2017 2016 Net cash receipts (payments) on settled derivatives $ (34,134 ) $ (2,618 ) $ (2,292 ) Gain (loss) from the change in fair value of open derivative contracts, net 153,472 (39,997 ) (12,853 ) Gain (loss) on commodity derivatives $ 119,338 $ (42,615 ) $ (15,145 )
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, 2018 and 2017 (in thousands): As of December 31, 2018: 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 $ 103,092 $ (18,815 ) $ 84,277 Commodity contracts Noncurrent assets - derivative instruments 31,899 (9,668 ) 22,231 Total assets $ 134,991 $ (28,483 ) $ 106,508 Liabilities Commodity contracts Current liabilities - derivative instruments $ 23,208 $ (18,815 ) $ 4,393 Commodity contracts Noncurrent liabilities - derivative instruments 11,162 (9,668 ) 1,494 Total liabilities $ 34,370 $ (28,483 ) $ 5,887 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

Debt Debt Disclosure (Tables)

Debt Debt Disclosure (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Debt	The Company’s debt consisted of the following at December 31, 2018 and December 31, 2017 : (in thousands) December 31, 2018 December 31, 2017 Senior secured revolving credit facility $ — $ 155,000 5.875% senior unsecured notes due 2026 500,000 — Debt issuance costs on senior unsecured notes (10,761 ) — Total long-term debt $ 489,239 $ 155,000

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2018 2017 2016 Incentive unit awards $ 76,442 $ 439,411 $ — Restricted stock unit awards 3,873 1,616 — Performance stock unit awards 2,530 1,497 — Restricted stock unit awards issued to nonemployee directors 501 452 — Total equity-based compensation expense $ 83,346 $ 442,976 $ —
Schedule of Share-based Compensation, Incentive Units, Activity	A summary of incentive unit award activity for the year ended December 31, 2018 is as follows: Weighted Average Grant-date Incentive Units Fair Value Unvested at December 31, 2017 7,755,745 $ 14.93 Granted 504,628 $ 13.21 Vested (2,789,511 ) $ 14.95 Forfeited (73,307 ) $ 12.21 Unvested at December 31, 2018 5,397,555 $ 14.79 Compensation costs remaining at December 31, 2018 (in millions) $ 5.7 Weighted average remaining period at December 31, 2018 (in years) 2.3
Schedule of Nonvested Restricted Stock Units Activity	A summary of RSU award activity for the year ended December 31, 2018 is as follows: Weighted Average Grant-date RSUs Fair Value Unvested at December 31, 2017 582,973 $ 12.44 Granted 716,734 $ 12.57 Vested (272,678 ) $ 12.40 Forfeited (155,910 ) $ 12.51 Unvested at December 31, 2018 871,119 $ 12.55 Compensation costs remaining at December 31, 2018 (in millions) $ 7.9 Weighted average remaining period at December 31, 2018 (in years) 2.1
Share-based Compensation, Performance Shares Award Unvested Activity	A summary of PSU award activity for the year ended December 31, 2018 is as follows: Weighted Average Grant-date PSUs Fair Value Unvested at December 31, 2017 398,566 $ 16.32 Granted 546,319 $ 16.23 Vested — $ — Forfeited (253,522 ) $ 16.32 Unvested at December 31, 2018 691,363 $ 16.25 Compensation costs remaining at December 31, 2018 (in millions) $ 7.2 Weighted average remaining period at December 31, 2018 (in years) 1.9
Schedule of Assumptions Used	The three -year performance period for the PSUs granted during the years ended December 31, 2018 and 2017 ends December 31, 2020 and December 31, 2019, respectively. The following table presents information regarding the weighted average fair value for the PSUs granted in 2018 and 2017 , including the assumptions used to determine the fair values: Years Ended December 31, 2018 2017 Dividend yield — % — % Volatility 37.3 % 55.7 % Risk-free interest rate 2.34 % 1.34 %

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
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: Year Ended From January 27, 2017, to (in thousands, except per share amounts) December 31, 2018 December 31, 2017 Net income (loss) attributable to Jagged Peak Energy Inc. stockholders $ 165,458 $ (76,458 ) Basic weighted average shares outstanding 213,128 212,932 Dilutive restricted stock units 75 — Dilutive performance stock units — — Diluted weighted average shares outstanding 213,203 212,932 Net income (loss) per common share: Basic $ 0.78 $ (0.36 ) Diluted $ 0.78 $ (0.36 )
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following table presents the weighted average number of outstanding equity awards that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive: Year Ended From January 27, 2017, to (in thousands) December 31, 2018 December 31, 2017 Number of antidilutive units: (1) Antidilutive restricted stock units 217 411 Antidilutive performance stock units 585 523 (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 antidilutive.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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 December 31, (in thousands) 2018 2017 Current income tax expense: Federal $ — $ — State — — — — Deferred income tax expense: Federal 64,364 56,350 State 2,111 1,593 66,475 57,943 Provision for income taxes $ 66,475 $ 57,943
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the income tax expense calculated at the federal statutory rate to the total income tax expense is as follows: Year Ended December 31, (in thousands) 2018 2017 Income (loss) before income taxes $ 231,933 $ (393,991 ) Less: loss before income taxes prior to corporate reorganization — (375,476 ) Income (loss) before income taxes subsequent to corporate reorganization $ 231,933 $ (18,515 ) Income tax expense (benefit) at the federal statutory rate $ 48,706 $ (6,480 ) Nondeductible equity-based compensation (1) 15,614 20,781 State income taxes, net of federal benefit 2,111 199 Other permanent differences 44 21 Income tax expense relating to change in tax status — 80,704 Federal tax reform changes - the Tax Act (2) — (37,282 ) Income tax expense (benefit) $ 66,475 $ 57,943 Effective tax rate 28.7 % (14.7 )% (1) 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 5 , Equity-based Compensation , for more information on the shares of common stock transferred to Management Holdco. (2) The Tax Act reduced the U.S. federal statutory rate from 35% to 21% beginning in 2018.
Schedule of Deferred Tax Assets and Liabilities	he components of the Company’s deferred income tax assets and liabilities are as follows: (in thousands) December 31, 2018 December 31, 2017 Deferred income tax assets: Commodity derivatives $ — $ 11,412 Equity-based compensation 1,963 928 Net operating loss carryforwards 19,788 16,093 Other 3,026 1,726 24,777 30,159 Deferred income tax liabilities: Oil and natural gas properties 127,468 88,102 Commodity derivatives 21,727 — 149,195 88,102 Net deferred income tax assets (liabilities) $ (124,418 ) $ (57,943 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 . Any ARO classified as current is included in accrued liabilities on the consolidated and combined balance sheets. (in thousands) 2018 2017 Asset retirement obligations at January 1, $ 929 $ 448 Liabilities incurred and assumed 718 590 Liability settlements and disposals (33 ) (190 ) Revisions of estimated liabilities 335 9 Accretion 123 72 Asset retirement obligations at December 31, 2,072 929 Less current portion of asset retirement obligations (126 ) (118 ) Long-term asset retirement obligations $ 1,946 $ 811

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value, Assets and Liabilities Measured on Recurring Basis	Level 2 (in thousands) December 31, 2018 December 31, 2017 Assets from commodity derivative contracts $ 134,991 $ 26 Liabilities due to commodity derivative contracts $ 34,370 $ 52,877
Fair Value, Liabilities Measured on Recurring Basis, Values Not Recorded at Fair Value	The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated and combined balance sheets: December 31, 2018 December 31, 2017 (in thousands) Principal Amount Fair Value Carrying Amount Fair Value Long-term debt: Senior secured revolving credit facility $ — $ — $ 155,000 $ 155,000 5.875% senior unsecured notes due 2026 $ 500,000 $ 466,250 $ — $ —
Impairment of unproved oil and natural gas property	The following table sets forth the noncash impairments of both proved and unproved properties for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 2016 Proved oil and natural gas property impairments $ — $ — $ — Unproved oil and natural gas property impairments (1) 28,198 373 372 $ 28,198 $ 373 $ 372 (1) Impairment of unproved oil and natural gas properties in 2018 primarily resulted from the Company’s ongoing evaluation of its undeveloped Big Tex acreage and the current plan to not drill on certain of these leases before they expire. Impairment of unproved oil and natural gas properties in 2017 and 2016 resulted from expirations of certain undeveloped leases.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 : (in thousands) 2019 2020 2021 2022 2023 Thereafter Total Operating leases $ 1,547 $ 1,539 $ 1,553 $ 1,559 $ 1,589 $ 7,378 $ 15,165 Service and purchase contracts (1) 7,598 1,285 750 — — — 9,633 Rig contracts 36,805 31,897 — — — — 68,702 Frac fleet contracts 63,135 — — — — — 63,135 Total $ 109,085 $ 34,721 $ 2,303 $ 1,559 $ 1,589 $ 7,378 $ 156,635 (1) Primarily relates to a retail power purchase agreement.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2018 2017 2016 Oryx via 3rd party shipper (1) $ 23,239 $ 10,058 $ 2,125 Oryx (2) $ 894 $ 798 $ 1,765 Phoenix (3) $ 364 $ 366 $ 338 Trident (3) $ 464 $ 236 $ 590 (1) Fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil transportation and 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 metering 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 _2

Organization, Operations and Basis of Presentation (Details) $ / shares in Units, $ in Thousands	Jan. 27, 2017USD ($)$ / sharesshares	Dec. 31, 2017	Dec. 31, 2018USD ($)segment	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jan. 26, 2017
Debt Instrument [Line Items]
Gross proceeds			$ 0	$ 401,625	$ 0
Expenses and underwriting discounts and commissions			$ 0	$ 3,216	$ 1,418
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			68.60%
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 Polici_4

Significant Accounting Policies and Related Matters - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 08, 2018
Concentration Risk [Line Items]
Assets or liabilities recorded for oil, natural gas or NGL imbalances		$ 0
Depletion	$ 220,300,000	109,200,000	$ 39,400,000
Proved oil and natural gas property impairments		0	0
Impairment of unproved property for leases	28,198,000	373,000	372,000
Dry hole costs	0	0	1,192,000	$ 0
Depreciation expense	1,900,000	1,700,000	900,000
Matching contributions	$ 700,000	500,000	200,000
Minimum | Property, Plant and Equipment, Other Types
Concentration Risk [Line Items]
Estimated useful life	3 years
Maximum | Property, Plant and Equipment, Other Types
Concentration Risk [Line Items]
Estimated useful life	30 years
Level 3
Concentration Risk [Line Items]
Proved oil and natural gas property impairments	$ 0	0	0
Level 3 | Unproved Oil And Gas Properties
Concentration Risk [Line Items]
Impairment of unproved property for leases	$ 28,200,000	$ 400,000	$ 400,000
Senior Notes | Senior Unsecured Notes due 2026
Concentration Risk [Line Items]
Stated interest rate of senior unsecured notes					5.875%

Significant Accounting Polici_5

Significant Accounting Policies and Related Matters - Schedule of Accounts Receivable (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 61,186,000	$ 50,734,000
Allowance for Doubtful Accounts Receivable, Current	0	0
Oil and gas sales
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	40,465,000	42,869,000
Joint interest
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	14,058,000	7,860,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 6,663,000	$ 5,000

Significant Accounting Polici_6

Significant Accounting Policies and Related Matters - Schedules of Concentration of Risk, by Risk Factor (Details) - Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Trafigura Trading, LLC
Concentration Risk [Line Items]
Concentration risk percent	85.00%	78.00%	57.00%
Sunoco Partners Marketing
Concentration Risk [Line Items]
Concentration risk percent	2.00%	11.00%	31.00%

Significant Accounting Polici_7

Significant Accounting Policies and Related Matters - Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Prepaid expenses	$ 1,626	$ 607
Other current assets	1	199
Total other current assets	$ 1,627	$ 806

Significant Accounting Polici_8

Significant Accounting Policies and Related Matters - Oil and Natural Gas Properties (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Exploratory dry hole costs	$ 0	$ 0	$ 1,192,000	$ 0
Proved oil and natural gas properties	1,746,766,000	1,012,321,000
Unproved oil and natural gas properties	158,732,000	183,510,000
Total oil and natural gas properties	1,905,498,000	1,195,831,000
Less: Accumulated depletion	(386,883,000)	(166,592,000)
Total oil and gas properties, net	$ 1,518,615,000	$ 1,029,239,000

Significant Accounting Polici_9

Significant Accounting Policies and Related Matters - Other Property And Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net	$ 1,530,285	$ 1,038,947
Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
Other property and equipment	16,021	12,167
Less: Accumulated depreciation	(4,351)	(2,459)
Property, Plant and Equipment, Net	$ 11,670	$ 9,708
Maximum | Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
Estimated useful life	30 years
Minimum | Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years

Significant Accounting Polic_10

Significant Accounting Policies and Related Matters - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Accrued capital expenditures	$ 74,688	$ 102,956
Accrued accounts payable	5,941	8,488
Royalties payable	19,964	6,105
Other current liabilities	29,419	14,762
Total accrued liabilities	$ 130,012	$ 132,311

Significant Accounting Polic_11

Significant Accounting Policies and Related Matters - Recent Accounting Pronouncements (Details) - USD ($) $ in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Total revenues		$ 581,644	$ 267,312	$ 76,522
Gathering and processing expenses		0	4,424	1,046
Net income (loss)	$ (76,458)	165,458	(451,934)	(9,760)
Oil sales
Disaggregation of Revenue [Line Items]
Revenues		539,802	241,788	70,078
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues		9,136	9,065	2,213
NGL sales
Disaggregation of Revenue [Line Items]
Revenues		31,956	15,571	3,068
Other operating revenues
Disaggregation of Revenue [Line Items]
Other operating revenues		750	$ 888	$ 1,163
Gathering and processing expenses
Disaggregation of Revenue [Line Items]
Gathering and processing expenses		0
Previous Revenue Recognition Method
Disaggregation of Revenue [Line Items]
Total revenues		596,375
Gathering and processing expenses		14,731
Net income (loss)		165,458
Previous Revenue Recognition Method | Oil sales
Disaggregation of Revenue [Line Items]
Revenues		539,802
Previous Revenue Recognition Method | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues		12,624
Previous Revenue Recognition Method | NGL sales
Disaggregation of Revenue [Line Items]
Revenues		43,199
Previous Revenue Recognition Method | Other operating revenues
Disaggregation of Revenue [Line Items]
Other operating revenues		750
Accounting Standards Update 2016-02
Disaggregation of Revenue [Line Items]
Contractual obligations related to noncancelable leases and contracts		83,900
Accounting Standards Update 2014-09 | ASC 606 Adjustments
Disaggregation of Revenue [Line Items]
Total revenues		14,731
Net income (loss)		0
Accounting Standards Update 2014-09 | ASC 606 Adjustments | Oil sales
Disaggregation of Revenue [Line Items]
Revenues		0
Accounting Standards Update 2014-09 | ASC 606 Adjustments | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues		3,488
Accounting Standards Update 2014-09 | ASC 606 Adjustments | NGL sales
Disaggregation of Revenue [Line Items]
Revenues		11,243
Accounting Standards Update 2014-09 | ASC 606 Adjustments | Other operating revenues
Disaggregation of Revenue [Line Items]
Other operating revenues		0
Accounting Standards Update 2014-09 | ASC 606 Adjustments | Gathering and processing expenses
Disaggregation of Revenue [Line Items]
Gathering and processing expenses		$ 14,731

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Derivatives (Details) - Not Designated as Hedging Instrument	12 Months Ended
	Dec. 31, 2018$ / bblbbl
First quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	1,890,000
Wtd Avg Price ($/Bbl) | $ / bbl	59.95
Second quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	1,911,000
Wtd Avg Price ($/Bbl) | $ / bbl	59.95
Third quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	1,932,000
Wtd Avg Price ($/Bbl) | $ / bbl	59.95
Fourth quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	1,932,000
Wtd Avg Price ($/Bbl) | $ / bbl	59.95
Total 2,019
Derivative [Line Items]
Volumes (Bbls) | bbl	7,665,000
Wtd Avg Price ($/Bbl) | $ / bbl	59.95
Year ending December 31, 2020
Derivative [Line Items]
Volumes (Bbls) | bbl	2,928,000
Wtd Avg Price ($/Bbl) | $ / bbl	60.82
First quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	2,070,000
Wtd Avg Price ($/Bbl) | $ / bbl	(7.17)
Second quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	2,093,000
Wtd Avg Price ($/Bbl) | $ / bbl	(7.17)
Third quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	2,300,000
Wtd Avg Price ($/Bbl) | $ / bbl	(4.79)
Fourth quarter 2019
Derivative [Line Items]
Volumes (Bbls) | bbl	2,300,000
Wtd Avg Price ($/Bbl) | $ / bbl	(4.79)
Total 2,019
Derivative [Line Items]
Volumes (Bbls) | bbl	8,763,000
Wtd Avg Price ($/Bbl) | $ / bbl	(5.92)
Year ending December 31, 2020
Derivative [Line Items]
Volumes (Bbls) | bbl	9,516,000
Wtd Avg Price ($/Bbl) | $ / bbl	(1.31)

Derivative Instruments - Gains

Derivative Instruments - Gains (Losses) in Earnings (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Net cash receipts (payments) on settled derivatives	$ 34,134	$ 2,618	$ 2,292
Gain (loss) on derivative instruments, net	119,338	(42,615)	(15,145)
Commodity contracts
Derivative [Line Items]
Net cash receipts (payments) on settled derivatives	(34,134)	(2,618)	(2,292)
Gain (loss) on derivative instruments, net	153,472	(39,997)	(12,853)
Gain (loss) on commodity derivatives	$ 119,338	$ (42,615)	$ (15,145)

Derivative Instruments - Balanc

Derivative Instruments - Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, assets	$ 134,991	$ 26
Netting adjustments not offset on the balance sheet, assets	(28,483)	(26)
Assets from commodity derivative contracts, assets	106,508	0
Gross amounts presented on the balance sheet, liabilities	34,370	52,877
Netting adjustments not offset on the balance sheet, liabilities	(28,483)	(26)
Liabilities from commodity derivative contracts, liabilities	5,887	52,851
Commodity contracts | Current assets - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, assets	103,092	0
Netting adjustments not offset on the balance sheet, assets	(18,815)	0
Assets from commodity derivative contracts, assets	84,277	0
Commodity contracts | Noncurrent assets - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, assets	31,899	26
Netting adjustments not offset on the balance sheet, assets	(9,668)	(26)
Assets from commodity derivative contracts, assets	22,231	0
Commodity contracts | Current liabilities - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, liabilities	23,208	41,782
Netting adjustments not offset on the balance sheet, liabilities	(18,815)	0
Liabilities from commodity derivative contracts, liabilities	4,393	41,782
Commodity contracts | Noncurrent liabilities - derivative instruments
Derivatives, Fair Value [Line Items]
Gross amounts presented on the balance sheet, liabilities	11,162	11,095
Netting adjustments not offset on the balance sheet, liabilities	(9,668)	(26)
Liabilities from commodity derivative contracts, liabilities	$ 1,494	$ 11,069

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details)	Dec. 31, 2018counterparty
Commodity contracts
Derivative [Line Items]
Number of counterparties	6

Debt Obligations (Details)

Debt Obligations (Details)	May 08, 2018USD ($)	Jun. 30, 2018	Apr. 30, 2018USD ($)	Mar. 31, 2018	Feb. 28, 2017	Jun. 30, 2015	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Nov. 30, 2018USD ($)	Aug. 31, 2018USD ($)
Debt Instrument [Line Items]
Total long-term debt							$ 489,239,000	$ 155,000,000
Debt issuance costs on senior unsecured notes							(10,761,000)	0
Repayments of lines of credit							320,000,000	142,000,000	$ 0
Long-term debt							489,239,000	155,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Reasonably Anticipated Forecasted Production, Percent Hedged		60.00%
Forecasted Production, Percent Hedged		85.00%
Proved Reserves, Percent Hedged		75.00%
Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Duration of Reasonably Anticipated Future Production That Can Be Hedged		37 months
Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Duration of Future Production That Can Be Hedged		36 months
Duration of Reasonably Anticipated Future Production That Can Be Hedged		60 months
Production Hedge Term		5 years
Revolving Credit Facility | Amended and Restated Credit Facility
Debt Instrument [Line Items]
Current borrowing capacity										$ 900,000,000	$ 825,000,000
Line of Credit Facility Elected Borrowing Capacity			$ 475,000,000							$ 540,000,000	$ 540,000,000
Balance outstanding								155,000,000
Capitalized interest							$ (1,200,000)
Repayments of lines of credit			$ 320,000,000
Percent of proved reserves (at least)					90.00%
Minimum current ratio							1
Maximum leverage ratio							4
Revolving Credit Facility | Amendment No. 2
Debt Instrument [Line Items]
Current borrowing capacity							$ 540,000,000
Revolving Credit Facility | Amendment No. 2 | Minimum
Debt Instrument [Line Items]
Commitment fee				0.375%
Revolving Credit Facility | Amendment No. 2 | Maximum
Debt Instrument [Line Items]
Commitment fee				0.50%
Revolving Credit Facility | Amendment No. 2 | Federal Funds Effective Rate
Debt Instrument [Line Items]
Basis spread on variable rate				0.50%
Revolving Credit Facility | Amendment No. 2 | Federal Funds Effective Rate | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate				0.50%
Revolving Credit Facility | Amendment No. 2 | Federal Funds Effective Rate | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate				1.50%
Revolving Credit Facility | Amendment No. 2 | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate				1.00%
Revolving Credit Facility | Amendment No. 2 | LIBOR | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate				1.50%
Revolving Credit Facility | Amendment No. 2 | LIBOR | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate				2.50%
JPE LLC | Revolving Credit Facility | The Credit Facility
Debt Instrument [Line Items]
Debt term						5 years
Current borrowing capacity								425,000,000
Borrowing capacity remaining								$ 270,000,000
Weighted average interest rate								3.68%
Capitalized interest								$ (300,000)
Senior Notes | Senior Unsecured Notes due 2026
Debt Instrument [Line Items]
Total long-term debt							500,000,000
Stated interest rate of senior unsecured notes	5.875%
Aggregate principal of senior unsecured notes	$ 500,000,000
Proceeds from issuance of debt	$ 488,300,000
Redemption price of long term debt for certain defined changes of control	101.00%
Level 2 | Revolving Credit Facility | Amended and Restated Credit Facility
Debt Instrument [Line Items]
Total long-term debt							$ 0	$ 155,000,000

Equity-based Compensation - Add

Equity-based Compensation - Additional Information (Details) - USD ($)	1 Months Ended			3 Months Ended	12 Months Ended
	Mar. 31, 2017	Jan. 26, 2017	Apr. 30, 2016	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	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					$ 83,346,000	$ 442,976,000	$ 0
Incentive unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation			$ 14,700,000		$ 76,442,000	$ 439,411,000	$ 0
Vesting period					3 years
Fair value of vested units					$ 35,400,000
Granted (in shares)					504,628
Weighted average grant date fair value (in dollars per share)					$ 13.21	$ 12.45	$ 0
Compensation costs remaining					$ 5,700,000
Weighted average remaining period					2 years 3 months 18 days
Restricted stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation					$ 3,873,000	$ 1,616,000	$ 0
Fair value of vested units					$ 3,400,000	$ 0
Granted (in shares)					716,734
Weighted average grant date fair value (in dollars per share)					$ 12.57	$ 12.45	$ 0
Compensation costs remaining					$ 7,900,000
Weighted average remaining period					2 years 1 month 6 days
Performance stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation					$ 2,530,000	$ 1,497,000	$ 0
Fair value of vested units					$ 0	$ 0
Granted (in shares)					546,319
Weighted average grant date fair value (in dollars per share)					$ 16.23	$ 16.32
Compensation costs remaining					$ 7,200,000
Weighted average remaining period					1 year 10 months 24 days
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		$ 379,000,000			$ 76,400,000
Compensation modification				$ 71,300,000
Fair value of vested units					$ 25,200,000
Unallocated shares held (in shares)					0
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)					30,753
Weighted average grant date fair value (in dollars per share)					$ 13.17
Compensation costs remaining					$ 100,000
Weighted average remaining period					3 months 18 days

Equity-based Compensation - Sha

Equity-based Compensation - Share-based Compensation Expense (Details) - USD ($)	1 Months Ended	12 Months Ended
	Apr. 30, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total equity-based compensation expense		$ 83,346,000	$ 442,976,000	$ 0
Incentive unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Weighted average grant date fair value (in dollars per share)		$ 13.21	$ 12.45	$ 0
Total equity-based compensation expense	$ 14,700,000	$ 76,442,000	$ 439,411,000	$ 0
Restricted stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Weighted average grant date fair value (in dollars per share)		$ 12.57	$ 12.45	$ 0
Total equity-based compensation expense		$ 3,873,000	$ 1,616,000	$ 0
Performance stock unit awards
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Weighted average grant date fair value (in dollars per share)		$ 16.23	$ 16.32
Total equity-based compensation expense		$ 2,530,000	$ 1,497,000	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		$ 501,000	$ 452,000	$ 0

Equity-based Compensation - Sto

Equity-based Compensation - Stock Options Activity (Details) - Profit Interest Awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Incentive Units
Unvested beginning balance (in shares)	7,755,745
Granted (in shares)	504,628
Vested (in shares)	(2,789,511)
Forfeited (in shares)	(73,307)
Unvested ending balance (in shares)	5,397,555	7,755,745
Compensation costs remaining	$ 5.7
Weighted average remaining period	2 years 3 months 18 days
Weighted Average Grant-date Fair Value
Unvested beginning balance (in dollars per share)	$ 14.93
Granted (in dollars per share)	13.21	$ 12.45	$ 0
Vested (in dollars per share)	14.95
Forfeited (in dollars per share)	12.21
Unvested ending balance (in dollars per share)	$ 14.79	$ 14.93

Equity-based Compensation - Non

Equity-based Compensation - Nonvested Restricted Stock Units Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Incentive unit awards
RSUs
Unvested beginning balance (in shares)	7,755,745
Granted (in shares)	504,628
Vested (in shares)	(2,789,511)
Forfeited (in shares)	(73,307)
Unvested ending balance (in shares)	5,397,555	7,755,745
Fair value of vested units	$ 35,400,000
Compensation costs remaining	$ 5,700,000
Weighted average remaining period	2 years 3 months 18 days
Weighted Average Grant-date Fair Value
Unvested beginning balance (in dollars per share)	$ 14.93
Granted (in dollars per share)	13.21	$ 12.45	$ 0
Vested (in dollars per share)	14.95
Forfeited (in dollars per share)	12.21
Unvested ending balance (in dollars per share)	$ 14.79	$ 14.93
Restricted stock unit awards
RSUs
Unvested beginning balance (in shares)	582,973
Granted (in shares)	716,734
Vested (in shares)	(272,678)
Forfeited (in shares)	(155,910)
Unvested ending balance (in shares)	871,119	582,973
Fair value of vested units	$ 3,400,000	$ 0
Compensation costs remaining	$ 7,900,000
Weighted average remaining period	2 years 1 month 6 days
Weighted Average Grant-date Fair Value
Unvested beginning balance (in dollars per share)	$ 12.44
Granted (in dollars per share)	12.57	$ 12.45	$ 0
Vested (in dollars per share)	12.40
Forfeited (in dollars per share)	12.51
Unvested ending balance (in dollars per share)	$ 12.55	$ 12.44

Equity-based Compensation - N_2

Equity-based Compensation - Nonvested Performance Shares Award Activity (Details) - PSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
PSUs
Unvested beginning balance (in shares)	398,566
Granted (in shares)	546,319
Vested (in shares)	0
Forfeited (in shares)	(253,522)
Unvested ending balance (in shares)	691,363	398,566
Compensation costs remaining	$ 7.2
Weighted average remaining period	1 year 10 months 24 days
Weighted Average Grant-date Fair Value
Unvested beginning balance (in dollars per share)	$ 16.32
Granted (in dollars per share)	16.23	$ 16.32
Vested (in dollars per share)	0
Forfeited (in dollars per share)	16.32
Unvested ending balance (in dollars per share)	$ 16.25	$ 16.32

Equity-based Compensation - Val

Equity-based Compensation - Valuation Assumptions (Details) - Performance stock unit awards - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividend yield	0.00%	0.00%
Volatility	37.30%	55.70%
Risk-free interest rate	2.34%	1.34%
Weighted average fair value of awards granted (in dollars per share)	$ 16.23	$ 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Line Items]
Net income (loss) attributable to Jagged Peak Energy Inc. stockholders	$ (76,458)	$ 165,458	$ (451,934)	$ (9,760)
Effect of dilutive securities:
Basic weighted average shares outstanding	212,932	213,128	212,932
Diluted weighted average shares outstanding (in shares)	212,932	213,203	212,932
Net income (loss) per common share:
Basic (in dollars per share)	$ (0.36)	$ 0.78	$ (0.36)
Diluted (in dollars per share)	$ (0.36)	$ 0.78	$ (0.36)
Restricted stock unit awards
Effect of dilutive securities:
Effect of dilutive securities (in shares)	0	75
Performance stock unit awards
Effect of dilutive securities:
Effect of dilutive securities (in shares)	0	0

Earnings Per Share - Antidiluti

Earnings Per Share - Antidilutive Securities (Details) - shares shares in Thousands	11 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
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	217
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	585

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Deferred income taxes	$ 80,700,000
Operating Loss Carryforwards, domestic	94,200,000
Operating loss carryforwards, expiring in 2037	75,500,000
Operating loss carryforwards not subject to expiration	18,800,000
Unrecognized tax benefits	0
Income tax penalties and interest accrued	$ 0
Provisional amount recorded for income tax		$ 0

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current income tax expense:
Federal	$ 0	$ 0
State	0	0
Current income taxes	0	0
Deferred income tax expense:
Federal	64,364	56,350
State	2,111	1,593
Deferred income taxes	66,475	57,943	$ 0
Provision for income taxes	$ 66,475	$ 57,943	$ 0

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ 231,933	$ (393,991)	$ (9,760)
Income (Loss) From Continuing Operations Before Income Taxes, Extraordinary Items, Noncontrolling Interest, Before Corporate Reorganization	0	(375,476)
Income (Loss) From Continuing Operations Before Income Taxes, Extraordinary Items, Noncontrolling Interest, Subsequent to Corporate Reorganization	231,933	(18,515)
Income tax expense (benefit) at the federal statutory rate	48,706	(6,480)
Nondeductible equity-based compensation	15,614	20,781
State income taxes, net of federal benefit	2,111	199
Other permanent differences	44	21
Income tax expense relating to change in tax status	0	80,704
Federal tax reform changes - the Tax Act	0	(37,282)
Provision for income taxes	$ 66,475	$ 57,943	$ 0
Effective tax rate	28.70%	(14.70%)

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred income tax assets:
Commodity derivatives	$ 0	$ 11,412
Equity-based compensation	1,963	928
Net operating loss carryforwards	19,788	16,093
Other	3,026	1,726
Total deferred tax assets	24,777	30,159
Deferred income tax liabilities:
Oil and natural gas properties	127,468	88,102
Commodity derivatives	21,727	0
Total deferred tax liabilities	149,195	88,102
Net deferred income tax assets (liabilities)	$ (124,418)	$ (57,943)

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning balance	$ 929	$ 448
Liabilities incurred and assumed	718	590
Liability settlements and disposals	(33)	(190)
Revisions of estimated liabilities	335	9
Accretion	123	72
Asset retirement obligation, ending balance	2,072	929
Less current portion of asset retirement obligations	(126)	(118)
Long-term asset retirement obligations	$ 1,946	$ 811

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative contracts	$ 134,991,000	$ 26,000
Liabilities due to commodity derivative contracts	34,370,000	52,877,000
Principal Amount	489,239,000	155,000,000
Proved oil and natural gas property impairments		0	$ 0
Impairment of unproved oil and natural gas properties	28,198,000	373,000	372,000
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved oil and natural gas property impairments	0	0	0
Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative contracts	134,991,000	26,000
Liabilities due to commodity derivative contracts	34,370,000	52,877,000
Revolving Credit Facility | Amended and Restated Credit Facility | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Principal Amount	0	155,000,000
Senior secured revolving credit facility	0	155,000,000
Unproved Oil And Gas Properties | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of unproved oil and natural gas properties	28,200,000	400,000	$ 400,000
Senior Notes | Senior Unsecured Notes due 2026
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Principal Amount	500,000,000
Senior Notes | Senior Unsecured Notes due 2026 | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Principal Amount	500,000,000	0
5.875% senior unsecured notes due 2026	$ 466,250,000	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Minimum Rental Payments for Operating Leases (Details) $ in Thousands	Dec. 31, 2018USD ($)
Operating Leased Assets [Line Items]
2,019	$ 109,085
2,020	34,721
2,021	2,303
2,022	1,559
2,023	1,589
Thereafter	7,378
Total	156,635
Operating leases
Operating Leased Assets [Line Items]
2,019	1,547
2,020	1,539
2,021	1,553
2,022	1,559
2,023	1,589
Thereafter	7,378
Total	15,165
Service and purchase contracts
Operating Leased Assets [Line Items]
2,019	7,598
2,020	1,285
2,021	750
2,022	0
2,023	0
Thereafter	0
Total	9,633
Rig contracts
Operating Leased Assets [Line Items]
2,019	36,805
2,020	31,897
2,021	0
2,022	0
2,023	0
Thereafter	0
Total	68,702
Frac fleet contracts
Operating Leased Assets [Line Items]
2,019	63,135
2,020	0
2,021	0
2,022	0
2,023	0
Thereafter	0
Total	$ 63,135

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2019USD ($)contract	Nov. 30, 2018bbl	Dec. 31, 2019contract	Dec. 31, 2018USD ($)contractfrac_fleet_contract	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2019USD ($)
Loss Contingencies [Line Items]
Lease incentives				$ 4.7
Rent expense				$ 2.3	$ 0.9	$ 0.6
Number of drilling rig contracts | contract				7
Early termination penalties				$ 37.7
Contract agreement term		5 years
Minimum gross volume commitment | bbl		30,000
Frac fleet contracts
Loss Contingencies [Line Items]
Frac fleet under contract | frac_fleet_contract				2
Office Equipment
Loss Contingencies [Line Items]
Lease expiration period				5 years
Subsequent Event
Loss Contingencies [Line Items]
Number of drilling rig contracts terminated | contract	2
Number of drilling rig contracts on well-to-well contracts | contract	1
Early termination charges	$ 0.3
Number of frac fleet contracts terminated | contract			1
Subsequent Event | Frac fleet contracts
Loss Contingencies [Line Items]
Termination fees							$ 3.2

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	11 Months Ended	12 Months Ended
	Nov. 30, 2018	Dec. 31, 2017	Dec. 31, 2018	Jan. 26, 2017
Related Party Transaction [Line Items]
Contract agreement term	5 years
Outstanding payables		$ 1.8	$ 2.6
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			68.60%
Oryx Midstream Services, LLC | Oil Gathering Agreement
Related Party Transaction [Line Items]
Contract agreement term			12 years
Oryx Midstream Services, LLC | Investee | Quantum
Related Party Transaction [Line Items]
Ownership interest			41.50%
Phoenix Lease Services, LLC | Investee | Quantum
Related Party Transaction [Line Items]
Ownership interest			62.00%

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Phoenix Lease Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	$ 364	$ 366	$ 338
Trident Water Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	464	236	590
Oil Gathering Agreement | Oryx Midstream Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	23,239	10,058	2,125
Leasing of Equipment | Oryx Midstream Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	$ 894	$ 798	$ 1,765