10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

For the quarterly period ended September 30, 2019 

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-37995

Jagged Peak Energy Inc.

(Exact name of registrant as specified in its charter)

Delaware	81-3943703
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification Number)

1401 Lawrence Street, Suite 1800
Denver,	Colorado	80202
(Address of principal executive offices)		(Zip Code)

(720) 215-3700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐  

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☑  No ☐ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company	Emerging growth company
☑	☐	☐	☐	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐  No ☑

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Ticker Symbol	Name of each exchange on which registered
Common stock, par value $0.01 per share	JAG	New York Stock Exchange

The registrant had 213,413,380 shares of common stock outstanding at November 1, 2019.

TABLE OF CONTENTS

		Page
Glossary of Oil and Natural Gas Terms		1
Cautionary Statement Regarding Forward-Looking Statements		2
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Consolidated Balance Sheets	4
	Consolidated Statements of Operations	5
	Consolidated Statements of Changes in Equity	6
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8
	Note 1—Organization, Operations and Basis of Presentation	8
	Note 2—Significant Accounting Policies and Related Matters	8
	Note 3—Derivative Instruments	11
	Note 4—Debt	13
	Note 5—Equity-based Compensation	14
	Note 6—Earnings Per Share	15
	Note 7—Income Taxes	16
	Note 8—Asset Retirement Obligation	16
	Note 9—Fair Value Measurements	16
	Note 10—Leases	18
	Note 11—Commitments and Contingencies	20
	Note 12—Related Party Transactions	20
	Note 13—Subsequent Events	21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	37
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
Signatures		42

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Bbl.    One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

Boe.    One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Boe/d.    One Boe per day.

Completion.    The installation of permanent equipment for production of oil, natural gas or NGLs or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Differential.    An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Gross acres or gross wells.    The total acres or wells, as the case may be, in which a working interest is owned.

MBbl.    One thousand barrels of crude oil, condensate or NGLs.

MBoe.    One thousand Boe.

Mcf.    One thousand cubic feet of natural gas.

Mcf/d.    One Mcf per day.

MMBbl.    One million barrels of crude oil, condensate or NGLs.

MMcf.    One million cubic feet of natural gas.

MMcf/d.    One MMcf per day.

Net acres or net wells.    The sum of the fractional working interest owned in gross acres or gross wells, as the case may be. For example, an owner who has 50% interest in 100 acres owns 50 net acres. Likewise, an owner who has a 50% working interest in a well has a 0.50 net well.

NGL(s).    Natural gas liquid(s). Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

NYMEX.    The New York Mercantile Exchange.

Proved properties.    Properties with proved reserves.

Realized price.    The cash market price less all expected quality, transportation and demand adjustments.

Unproved properties.    Lease acreage with no proved reserves.

Waha Hub.    A natural gas delivery point in Pecos County, Texas that serves as a benchmark price for natural gas.

Working interest.    The right granted to the lessee of a property to develop and produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

Workover.    Operations on a producing well to restore or increase production.

WTI.    West Texas Intermediate. A market index price for oil that is widely quoted by financial markets.

1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Form 10-Q includes “forward-looking statements.” All statements, other than statements of historical fact included in or incorporated by reference into this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018 and this Quarterly Report on Form 10-Q.

Forward-looking statements include statements about:

• our business strategy;

• our reserves;

• our drilling prospects, inventories, projects and programs;

• our intention to replace the reserves we produce through drilling and property acquisitions;

• our financial strategy, liquidity and capital required for our drilling program, including our assessment of the sufficiency of our liquidity to fund our capital program and the amount and allocation of our capital program in 2019;

• our expected noncash compensation expenses;

• our expected pricing and realized oil, natural gas and NGL prices;

• the timing and amount of our future production of oil, natural gas and NGLs, including our ability to satisfy minimum gross volume commitments under certain marketing agreements;

• our future drilling plans;

• government regulations and our ability to obtain permits and governmental approvals;

• our pending legal or environmental matters;

• our marketing of oil, natural gas and NGLs;

• our leasehold or business acquisitions;

• our costs of developing our properties, including our capital budget;

• our hedging strategy and results;

• general economic conditions;

• uncertainty regarding our future operating results;

• our pending merger with a wholly owned subsidiary of Parsley Energy, Inc. and the expected timing of the consummation of the merger; and

• our plans, objectives, expectations and intentions contained in this quarterly report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018 and this Quarterly Report on Form 10-Q.

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact our strategy and change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in the above mentioned Form 10-K or this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

2

All forward-looking statements, expressed or implied, included in this Form 10-Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

3

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

JAGGED PEAK ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	September 30,			December 31,
	2019			2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,603		$	35,229
Accounts receivable	62,062			61,186
Derivative instruments	48,006			103,092
Prepaid and other current assets	3,158			1,627
Total current assets	123,829			201,134
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method	2,377,765			1,905,498
Accumulated depletion	(569,733		)	(386,883		)
Total oil and gas properties, net	1,808,032			1,518,615
Other property and equipment, net	10,155			11,670
Total property and equipment, net	1,818,187			1,530,285
OTHER NONCURRENT ASSETS
Operating lease right-of-use assets	47,489			—
Derivative instruments	13,961			31,899
Other assets	3,279			3,823
Total noncurrent assets	64,729			35,722
TOTAL ASSETS	$	2,006,745		$	1,767,141
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	23,531		$	34,762
Accrued liabilities	136,855			130,012
Operating lease liabilities	36,263			—
Derivative instruments	27,738			23,208
Total current liabilities	224,387			187,982
LONG-TERM LIABILITIES
Long-term debt	705,269			489,239
Derivative instruments	4,659			11,162
Asset retirement obligations	2,609			1,946
Deferred income taxes	118,432			124,418
Operating lease liabilities	15,519			—
Other long-term liabilities	—			4,444
Total long-term liabilities	846,488			631,209
Commitments and contingencies
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value; 50,000,000 shares authorized, none issued	—			—
Common stock, $0.01 par value; 1,000,000,000 shares authorized, 213,404,153 shares issued at September 30, 2019; 213,187,780 shares issued at December 31, 2018	2,134			2,132
Additional paid-in capital	867,159			856,818
Retained earnings	66,577			89,000
Total stockholders’ equity	935,870			947,950
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,006,745		$	1,767,141

The accompanying Notes are an integral part of these unaudited consolidated financial statements.

4

JAGGED PEAK ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
REVENUES
Oil sales	$	147,710		$	141,598		$	416,824		$	410,935
Natural gas sales	727			2,552			904			7,765
NGL sales	1,628			10,814			8,680			23,721
Other operating revenues	—			414			9			686
Total revenues	150,065			155,378			426,417			443,107
OPERATING EXPENSES
Lease operating expenses	17,554			11,184			46,758			31,390
Production and ad valorem taxes	11,263			9,517			32,100			26,437
Exploration	3			23			3			24
Depletion, depreciation, amortization and accretion	66,069			57,660			186,365			160,552
Impairment of unproved oil and natural gas properties	31,817			—			32,763			53
General and administrative expenses (including equity-based compensation of $4,098 and $2,614 for the three months ended September 30, 2019 and 2018, respectively, and $11,025 and $80,671 for the nine months ended September 30, 2019 and 2018, respectively)	13,669			12,321			40,141			109,471
Other operating expenses	—			19			3,206			65
Total operating expenses	140,375			90,724			341,336			327,992
INCOME (LOSS) FROM OPERATIONS	9,690			64,654			85,081			115,115
OTHER INCOME (EXPENSE)
Gain (loss) on commodity derivatives	39,421			(96,516		)	(85,702		)	(110,426		)
Interest expense, net	(9,974		)	(8,256		)	(27,683		)	(17,095		)
Gain on sale of oil and natural gas properties	—			6,225			—			6,225
Other, net	18			12			(105		)	30
Total other income (expense)	29,465			(98,535		)	(113,490		)	(121,266		)
INCOME (LOSS) BEFORE INCOME TAX	39,155			(33,881		)	(28,409		)	(6,151		)
Income tax expense (benefit)	8,597			(7,315		)	(5,986		)	14,737
NET INCOME (LOSS)	$	30,558		$	(26,566	)	$	(22,423	)	$	(20,888	)
Net income (loss) per common share:
Basic	$	0.14		$	(0.12	)	$	(0.11	)	$	(0.10	)
Diluted	$	0.14		$	(0.12	)	$	(0.11	)	$	(0.10	)
Weighted average common shares outstanding:
Basic	213,403			213,180			213,349			213,109
Diluted	213,700			213,180			213,349			213,109

The accompanying Notes are an integral part of these unaudited consolidated financial statements.

5

JAGGED PEAK ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

(in thousands)

	Common Stock			Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Total Stockholders' Equity
	Shares	Amount
BALANCE AT DECEMBER 31, 2018	213,188	$	2,132	$	856,818		$	89,000		$	947,950
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	167	2		(281		)	—			(279		)
Equity-based compensation	—	—		2,934			—			2,934
Net income (loss)	—	—		—			(94,888		)	(94,888		)
BALANCE AT MARCH 31, 2019	213,355	2,134		859,471			(5,888		)	855,717
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	39	—		(376		)	—			(376		)
Equity-based compensation	—	—		3,993			—			3,993
Net income (loss)	—	—		—			41,907			41,907
BALANCE AT JUNE 30, 2019	213,394	2,134		863,088			36,019			901,241
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	10	—		(27		)	—			(27		)
Equity-based compensation	—	—		4,098			—			4,098
Net income (loss)	—	—		—			30,558			30,558
BALANCE AT SEPTEMBER 30, 2019	213,404	$	2,134	$	867,159		$	66,577		$	935,870
BALANCE AT DECEMBER 31, 2017	212,931	$	2,129	$	773,674		$	(76,458	)	$	699,345
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	180	2		(202		)	—			(200		)
Equity-based compensation	—	—		75,678			—			75,678
Net income (loss)	—	—		—			(39,403		)	(39,403		)
BALANCE AT MARCH 31, 2018	213,111	2,131		849,150			(115,861		)	735,420
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	68	1		—			—			1
Equity-based compensation	—	—		2,379			—			2,379
Net income (loss)	—	—		—			45,081			45,081
BALANCE AT JUNE 30, 2018	213,179	2,132		851,529			(70,780		)	782,881
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	2	—		—			—			—
Equity-based compensation	—	—		2,614			—			2,614
Net income (loss)	—	—		—			(26,566		)	(26,566		)
BALANCE AT SEPTEMBER 30, 2018	213,181	$	2,132	$	854,143		$	(97,346	)	$	758,929

The accompanying Notes are an integral part of these unaudited consolidated financial statements.

6

JAGGED PEAK ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(22,423	)	$	(20,888	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion expense	186,365			160,552
Impairment of unproved oil and natural gas properties	32,763			53
Amortization of debt issuance costs	1,770			1,753
Deferred income taxes	(5,986		)	14,737
Equity-based compensation	11,025			80,671
(Gain) loss on commodity derivatives	85,702			110,426
Net cash receipts (payments) on settled derivatives	(14,651		)	(33,705		)
(Gain) on sale of oil and natural gas properties	—			(6,225		)
Other	(98		)	(234		)
Change in operating assets and liabilities:
Accounts receivable and other current assets	(2,407		)	(29,854		)
Accounts payable and accrued liabilities	641			40,461
Net cash provided by operating activities	272,701			317,747
CASH FLOWS FROM INVESTING ACTIVITIES
Leasehold and acquisition costs	(32,931		)	(18,854		)
Development of oil and natural gas properties	(477,681		)	(551,059		)
Other capital expenditures	(837		)	(3,245		)
Proceeds from sale of oil and natural gas properties	—			8,377
Net cash used in investing activities	(511,449		)	(564,781		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from credit facility	215,000			165,000
Repayment of credit facility	—			(320,000		)
Proceeds from senior notes	—			500,000
Debt issuance costs	(197		)	(13,350		)
Employee tax withholding for settlement of equity compensation awards	(681		)	(200		)
Net cash provided by financing activities	214,122			331,450
NET CHANGE IN CASH AND CASH EQUIVALENTS	(24,626		)	84,416
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	35,229			9,523
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	10,603		$	93,939
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest	$	18,200		$	4,009
Cash paid for income taxes	—			—
Cash paid for operating lease liabilities included in cash flows from operating activities	1,123			—
Cash paid for operating lease liabilities included in cash flows from investing activities	26,918			—
SUPPLEMENTAL DISCLOSURE OF NONCASH OPERATING ACTIVITIES
Lease liabilities arising from obtaining right-of-use assets	$	73,413		$	—
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	102,275		$	100,780
Asset retirement obligations	1,619			567

The accompanying Notes are an integral part of these unaudited consolidated financial statements.

7

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

Note 1—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.

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”). Additional background on the Company, its IPO and details of the ownership of the Company are available in the Company's Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”).

Basis of Presentation

The accompanying unaudited interim consolidated 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”) for interim financial information, and should be read in conjunction with the financial statements, summary of significant accounting policies and footnotes included in the 2018 Form 10-K. Accordingly, certain disclosures required by GAAP and normally included in Annual Reports on Form 10-K have been condensed or omitted from this report; however, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in the 2018 Form 10-K. All significant intercompany balances and transactions have been eliminated.

It is the opinion of management that all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identical to its comprehensive income or loss. Operating results for the periods presented are not necessarily indicative of expected results for the full year because of the impact of fluctuations in prices received for oil, natural gas and NGLs, expected production changes due to development activities, natural production declines, the uncertainty of exploration and development drilling results, the fair value of derivative instruments and other factors.

Certain prior year amounts have been reclassified to conform to the current presentation.

Note 2—Significant Accounting Policies and Related Matters

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 2, Significant Accounting Policies and Related Matters, to the Company’s consolidated financial statements in its 2018 Form 10-K, and are supplemented by the notes to the consolidated financial statements in this Quarterly Report on Form 10-Q. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in these notes to the consolidated financial statements.

Use of Estimates

In the course of preparing the consolidated 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 financial statements include, among other things, (1) oil and natural gas reserve quantities, which impact depletion of oil and natural gas properties and evaluation and measurement of any impairment of proved oil and natural gas properties, (2) impairment of unproved oil and natural gas properties, which includes assumptions about future development and lease renewal, commodity price outlooks and prevailing market rates, (3) accrued operating and capital costs, (4) asset retirement obligation timing and costs, (5) lease terms and incremental borrowing rates used in the determination of lease assets and liabilities, (6) measurement of equity-based compensation, (7) fair value of derivative instruments, (8) deferred income taxes and (9) disclosure of commitments and contingencies. Changes in these estimates and assumptions could have a significant impact on results in future periods.

8

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

Revenue Recognition

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 from the Delaware Basin. The Company believes the disaggregation of revenues into oil sales, natural gas sales and NGL sales, as seen on the consolidated statements of operations, is an appropriate level of detail for its primary activity.

Contract Assets and Liabilities. The Company’s performance obligations for its contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company did not have any contract assets or liabilities as of September 30, 2019 and December 31, 2018.

Performance Obligations. 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. 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.

Accounts Receivable

At September 30, 2019 and December 31, 2018, accounts receivable was comprised of the following:

(in thousands)	September 30, 2019		December 31, 2018
Oil and gas sales	$	54,233	$	40,465
Joint interest	5,172		14,058
Other	2,657		6,663
Total accounts receivable	$	62,062	$	61,186

At September 30, 2019 and December 31, 2018, the Company did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented.

Oil and Natural Gas Properties

A summary of the Company’s oil and natural gas properties, net is as follows:

(in thousands)	September 30, 2019			December 31, 2018
Proved oil and natural gas properties	$	2,244,576		$	1,746,766
Unproved oil and natural gas properties	133,189			158,732
Total oil and natural gas properties	2,377,765			1,905,498
Less: Accumulated depletion	(569,733		)	(386,883		)
Total oil and natural gas properties, net	$	1,808,032		$	1,518,615

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 three months ended September 30, 2019 and 2018, the Company recorded depletion for oil and natural gas properties of $65.6 million and $57.2 million, respectively. For the nine months ended September 30, 2019 and 2018, the Company recorded depletion for oil and natural gas properties of $184.9 million and $159.0 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated statements of operations.

Leases

Following the adoption of Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) on January 1, 2019, the Company determines if an arrangement is a lease at inception of the contract. Operating lease right-of-use (“ROU”) assets and operating lease liabilities are recognized based on the present value of the future lease payments over the lease term at commencement date. For leases that do not provide implicit rates, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Operating lease ROU assets exclude lease incentives and initial direct costs incurred. Operating lease cost is recognized on a straight-line basis over the lease term. The Company currently does not have any finance leases.

9

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

The Company has lease agreements with lease and non-lease components, which are all accounted for as a single lease component.

Short-term leases have a term of 12 months or less. The Company recognizes short-term lease cost based on usage of the asset over the lease term and does not record a ROU asset or lease liability for such leases.

The Company monitors for events or changes in circumstances that may require a reassessment or impairment of its leases, at which time the Company's ROU assets for operating leases may be reduced by impairment losses. 

Accrued Liabilities

The components of accrued liabilities are shown below:

(in thousands)	September 30, 2019		December 31, 2018
Accrued capital expenditures	$	80,153	$	74,688
Accrued production and ad valorem taxes	12,765		7,802
Accrued interest	12,645		4,896
Royalties payable	9,684		19,964
Accrued LOE	9,944		8,014
Accrued accounts payable	1,454		5,941
Other current liabilities	10,210		8,707
Total accrued liabilities	$	136,855	$	130,012

Recent Accounting Pronouncements

Recently Adopted Accounting Standards

Leases. In February 2016, the Financial Accounting Standards Board (“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. ASU 2016-02 retains a distinction between operating and finance leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. Entities are required to recognize operating or finance leases as ROU assets and lease liabilities on the balance sheet as well as disclose key information about leasing arrangements in the notes to the financial statements. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. This ASU does not apply to leases of mineral rights to explore for or use oil and natural gas.

The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective approach as permitted under ASU 2018-11, which allows the Company to apply the legacy lease guidance and disclosure requirements (“ASC 840”) in the comparative periods presented for the year of adoption. The adoption did not require an adjustment to opening retained earnings for a cumulative effect adjustment.

As part of the adoption, the Company elected the short-term lease recognition policy election for all leases that qualify, and as such, no ROU assets or lease liabilities will be recorded on the balance sheet when the term of the lease is less than 12 months. The Company also elected the following practical expedients:

•the package of transition practical expedients, permitting the Company to not reassess its prior conclusions about lease identification, lease classification and initial direct costs;

•the practical expedient pertaining to land easements, which allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way; and

•the practical expedient to not separate lease and non-lease components.

The new lease standard impacted the Company’s consolidated balance sheets as a result of the ROU assets and operating lease liabilities but did not impact its consolidated statements of operations or consolidated statements of cash flows. The Company currently has no finance leases. The impact to the opening January 1, 2019 consolidated balance sheets was as follows:

10

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

(in thousands)	Opening Balances as of January 1, 2019		Adoption of ASC 842			As Adjusted at January 1, 2019
Operating lease right-of-use assets (1)	$	—	$	73,413		$	73,413
Current operating lease liabilities (1)	$	—	$	35,043		$	35,043
Long-term operating lease liabilities (1)	—		42,814			42,814
Other long-term liabilities (2)	4,444		(4,444		)	—

(1) Represents the recognition of operating lease ROU assets and the associated lease liabilities.

(2) Represents the derecognition of deferred rent and leasehold incentives that were accounted for under ASC 840.

Adoption of the new standard did not impact the Company’s previously reported consolidated balance sheets, results of operations, cash flows statements or statements of changes in equity.

For more information on the Company’s leases, refer to Note 10, Leases.

Accounting Standards Not Yet Adopted

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 current 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 will be applied using a modified retrospective approach which may result 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 not been significant, and the Company does not believe the adoption of ASU 2016-13 will have a material impact on its consolidated financial statements.

Note 3—Derivative Instruments

Objectives and Strategies

The Company is exposed to fluctuations in commodity prices received for its oil and natural gas production. To mitigate the volatility in its expected operating cash flows, the Company hedges a portion of its crude oil sales through derivative instruments. The Company does not use these instruments for speculative or trading purposes.

Commodity Derivatives

In an effort to reduce the variability of the Company’s cash flows, the Company hedges the commodity prices associated with a portion of its expected future oil volumes by entering into the following types of instruments:

Swaps. The Company receives a 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 Swaps. These instruments establish a fixed price differential between Cushing WTI prices and Midland WTI prices for the notional volumes contracted. The Company receives the fixed price differential and pays the floating market price differential to the counterparty.

The following table summarizes the Company’s derivative contracts as of September 30, 2019:

Contract Period	Volumes (MBbls)	Wtd Avg Price ($/Bbl)
Oil Swaps: (1)
Fourth quarter 2019	1,932	$	59.95
Year ending December 31, 2020	7,320	$	58.25
Oil Basis Swaps: (2)
Fourth quarter 2019	2,300	$	(4.79	)
Year ending December 31, 2020	9,516	$	(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.

11

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

Counterparty Risk

By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. 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.

At September 30, 2019, the Company had commodity derivative contracts with seven counterparties, all of which were lenders, or affiliates of 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.

Should the creditworthiness of the Company’s counterparties decline, under certain circumstances the Company may have a contractual right of offset against other amounts owed by the Company to the counterparty, but otherwise 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.

Financial Statement Presentation

The Company’s derivative instruments are carried at fair value on the consolidated balance sheets. The Company has elected to not apply hedge accounting; 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 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.

Consolidated Statements of Operations

The Company recognized the following gains (losses) on derivative instruments in its consolidated statements of operations for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2019			2018			2019			2018
Net gain (loss) on settled derivative instruments	$	(3,484	)	$	(6,347	)	$	(14,651	)	$	(33,705	)
Net gain (loss) from the change in fair value of open derivative instruments	42,905			(90,169		)	(71,051		)	(76,721		)
Gain (loss) on derivative instruments, net	$	39,421		$	(96,516	)	$	(85,702	)	$	(110,426	)

Consolidated Balance Sheets

The Company’s derivative instruments 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 balance sheets.

12

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of September 30, 2019 and December 31, 2018 (in thousands):

As of September 30, 2019:	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	$	48,006	$	(25,639	)	$	22,367
Commodity contracts	Noncurrent assets - derivative instruments	13,961		(4,659		)	9,302
Total assets		$	61,967	$	(30,298	)	$	31,669
Liabilities
Commodity contracts	Current liabilities - derivative instruments	$	27,738	$	(25,639	)	$	2,099
Commodity contracts	Noncurrent liabilities - derivative instruments	4,659		(4,659		)	—
Total liabilities		$	32,397	$	(30,298	)	$	2,099

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

Note 4—Debt

The Company’s debt consisted of the following at September 30, 2019 and December 31, 2018:

(in thousands)	September 30, 2019			December 31, 2018
Senior secured revolving credit facility	$	215,000		$	—
5.875% senior unsecured notes due 2026	500,000			500,000
Debt issuance costs on senior unsecured notes	(9,731		)	(10,761		)
Total long-term debt	$	705,269		$	489,239

Senior Secured Revolving Credit Facility

At December 31, 2018, the Company’s amended and restated credit facility, as amended (the “Amended and Restated Credit Facility”), had a borrowing base of $900.0 million with elected commitments of $540.0 million and nothing outstanding.

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:

Financial Covenant	Required Ratio
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than	1.0	to	1.0
Ratio of debt to EBITDAX, as defined in the credit agreement	Not greater than	4.0	to	1.0

13

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

As of September 30, 2019, the Company was in compliance with the financial covenants under its Amended and Restated Credit Facility .

As of September 30, 2019, the borrowing base and elected commitments remained at $900.0 million and $540.0 million, respectively, and the Company had $215.0 million outstanding and $325.0 million of elected commitments available. The weighted-average interest rate as of September 30, 2019 was 3.80%.

5.875% Senior Unsecured Notes due 2026

JPE LLC has $500.0 million aggregate principal amount of 5.875% senior unsecured notes that mature on May 1, 2026 (the “Senior Notes”). Interest is payable on the Senior Notes semi-annually in arrears on each May 1 and November 1.

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 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 March 2019 the Company completed 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).

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, pursuant to a change of control offer made by the Company pursuant to the terms of the indenture governing the Senior Notes.

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.

Note 5—Equity-based Compensation

Equity-based compensation expense, for each type of equity-based award, was as follows for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Incentive unit awards	$	856	$	609	$	2,050	$	75,767
Restricted stock unit awards	1,624		883		4,520		2,996
Performance stock unit awards	1,403		1,016		3,987		1,513
Restricted stock unit awards issued to nonemployee directors	215		106		468		395
Equity-based compensation expense	$	4,098	$	2,614	$	11,025	$	80,671

Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated statements of operations, will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, modification of awards, employee forfeitures and the timing of the awards.

For the nine months ended September 30, 2018, equity-based compensation expense included (1) $71.3 million related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO and (2) the reversal of equity-based compensation expense associated with awards that were forfeited during the nine months ended September 30, 2018, notably performance stock unit (“PSU”) awards forfeited by former executive officers. As the Company’s policy is to recognize forfeitures as they occur, previously recognized expense on unvested awards is reversed at the date of forfeiture.

14

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

The following table summarizes the Company’s award activity for incentive units, restricted stock units (“RSU”) and PSUs for the nine months ended September 30, 2019:

	Incentive Units (2)		RSUs		PSUs
Unvested at December 31, 2018	5,397,555		871,119		691,363
Awards Granted (1)	28,991		1,232,503		657,664
Vested	(2,598,796	)	(291,704	)	—
Forfeited	(28,991	)	(137,510	)	(135,299	)
Unvested at September 30, 2019	2,798,759		1,674,408		1,213,728

(1) The weighted average grant-date fair value was $8.27 for incentive units, $10.18 for RSUs and $12.63 for PSUs. The weighted average grant-date fair value for PSUs was calculated using a Monte Carlo simulation.

(2) Included in the unvested incentive units at September 30, 2019 are 2,433,821 units for which equity-based compensation expense has been accelerated and fully recognized.

The following table reflects the future equity-based compensation expense to be recorded for each type of award that was outstanding at September 30, 2019:

	Incentive Units		RSUs (1)		PSUs
Compensation costs remaining at September 30, 2019 (in millions)	$	3.5	$	13.8	$	9.5
Weighted average remaining period at September 30, 2019 (in years)	1.6		2.1		1.8

(1) The remaining compensation cost at September 30, 2019 for the nonemployee director RSUs was $0.5 million, with a weighted average remaining period of 0.6 years.

Note 6—Earnings Per Share

Basic earnings per share 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. Shares to be issued in exchange for incentive units are already outstanding and will not have a dilutive effect upon vesting. 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 antidilutive.

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share amounts)	2019		2018			2019			2018
Net income (loss) attributable to common stock	$	30,558	$	(26,566	)	$	(22,423	)	$	(20,888	)
Basic weighted average shares outstanding	213,403		213,180			213,349			213,109
Dilutive unvested RSUs	35		—			—			—
Dilutive unvested PSUs	262		—			—			—
Diluted weighted average shares outstanding	213,700		213,180			213,349			213,109
Net income (loss) per common share:
Basic	$	0.14	$	(0.12	)	$	(0.11	)	$	(0.10	)
Diluted	$	0.14	$	(0.12	)	$	(0.11	)	$	(0.10	)

15

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

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. These shares could dilute basic earnings per share in future periods.

	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands)	2019	2018	2019	2018
Number of antidilutive units: (1)
Antidilutive unvested RSUs	1,575	791	1,455	721
Antidilutive unvested PSUs	225	603	1,076	496

(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.

Note 7—Income Taxes

The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs.

Income tax expense was as follows for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2019			2018			2019			2018
Income tax expense (benefit)	$	8,597		$	(7,315	)	$	(5,986	)	$	14,737
Effective tax rate	22.0		%	21.6		%	21.1		%	(239.6		)%

For the nine months ended September 30, 2018, the Company’s effective tax rate differed from the federal statutory rate of 21% primarily due to nondeductible equity-based compensation related to incentive unit awards allocated at the time of the IPO, and permanent differences on vested equity-based compensation awards.

Note 8—Asset Retirement Obligations

The following table summarizes the changes in the carrying amount of the asset retirement obligations for the nine months ended September 30, 2019. The current portion of the asset retirement obligation liability is included in accrued liabilities on the consolidated balance sheets.

(in thousands)
Asset retirement obligations at January 1, 2019	$	2,072
Liabilities incurred and assumed	902
Liability settlements	(318		)
Revisions of estimated liabilities	717
Accretion	159
Asset retirement obligations at September 30, 2019	3,532
Less current portion of asset retirement obligations	(923		)
Long-term asset retirement obligations	$	2,609

During the nine months ended September 30, 2019, the Company recognized revisions of estimated liabilities totaling $0.7 million which were due to changes in estimated abandonment timing and costs.

Note 9—Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Financial assets and liabilities are measured at fair value on a recurring basis. Nonfinancial assets and liabilities, such as the initial measurement of asset retirement obligations and oil and natural gas properties upon acquisition or impairment, are recognized at fair value on a nonrecurring basis.

16

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

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 nine months ended September 30, 2019.

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)	September 30, 2019		December 31, 2018
Assets from commodity derivative contracts	$	61,967	$	134,991
Liabilities due to commodity derivative contracts	$	32,397	$	34,370

The fair value of the Company’s oil swaps and basis swaps is computed using discounted cash flows for the remaining duration of each commodity derivative instrument using the terms of the related contract. Inputs include published forward commodity price curves as of the date of the estimate. The Company compares these prices to the price parameters contained in its derivative 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 made using 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 balance sheets:

	September 30, 2019				December 31, 2018
(in thousands)	Principal Amount		Fair Value		Principal Amount		Fair Value
Long-term debt:
Senior secured revolving credit facility	$	215,000	$	215,000	$	—	$	—
5.875% senior unsecured notes due 2026	$	500,000	$	501,490	$	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 these inputs are classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes at September 30, 2019 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.

17

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

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 considers 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Proved oil and natural gas property impairments	$	—	$	—	$	—	$	—
Unproved oil and natural gas property impairments (1)	31,817		—		32,763		53
	$	31,817	$	—	$	32,763	$	53

(1) Impairment of unproved oil and natural gas properties in 2019 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 2018 resulted from expirations of certain undeveloped leases.

Asset retirement obligations. The inception value and new layers resulting from upward revisions of the Company’s asset retirement obligations 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.

Note 10—Leases

The Company’s ROU assets include leases for its drilling rigs, its corporate headquarters and certain office equipment, with the significant lease types described below in more detail. As of September 30, 2019, the Company’s leases have remaining lease terms of 0.5 years to 8.7 years. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company’s lease agreements do not contain any material restrictive covenants. Additionally, the Company currently does not have any finance leases.

Short-term leases have a term of 12 months or less. The Company recognizes short-term lease cost based on usage of the asset over the lease term. There are no ROU assets or lease liabilities recorded for such leases.

Drilling Rigs. The Company enters into short- and long-term contracts for drilling rigs with third parties to support its development plan. The short-term drilling rig arrangements can range from a term that is in effect until drilling operations are completed on a contractually specified well or well pad, or for a given number of months not to exceed 12 months. The Company’s long-term drilling contracts are generally structured with an initial noncancelable term of one to two years. Upon mutual agreement with the contractor, the Company typically has the option to extend the initial contract for additional wells, well pads or a contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.

18

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

The Company has determined that it cannot conclude with reasonable certainty that it will extend the drilling contracts past their respective primary term, and as a result, the Company uses the primary term in its calculation of the ROU asset and lease liability. The Company capitalizes the costs of its short- and long-term drilling rigs to oil and natural gas properties.

Corporate Headquarters. The Company leases office space for its corporate headquarters. The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the noncancelable term. As such, the Company uses the noncancelable term in its calculation of the ROU asset and lease liability. The lease for the Company’s corporate headquarters provides for increases in future minimum annual rental payments as defined in the lease agreement. The lease also includes real estate taxes and common area maintenance charges, which are expensed when occurred. The Company classifies its leases for office space as operating leases, with the costs recognized as “general and administrative expenses” in its consolidated statements of operations.

Lease Costs

Lease cost for operating leases is recognized on a straight-line basis over the lease term. Short-term lease costs exclude expenses related to leases with a lease term of one month or less. Lease costs are presented gross and a portion of these costs will be reimbursed by the Company’s other working interest partners for their proportionate share. The total gross lease cost for the periods indicated are as follows:

	Three months ended		Nine months ended
(in thousands)	September 30, 2019		September 30, 2019
Operating lease cost (1)	$	9,297	$	27,891
Short-term lease cost (2)	5,273		33,553
Variable lease cost (3)	369		941
Total lease cost	$	14,939	$	62,385

(1) The total operating lease cost may not agree to the cash paid for operating lease liabilities on the consolidated statements of cash flows due to the timing of cash payments and incurred costs.

(2) Short-term lease cost during the three months ended September 30, 2019 is primarily related to one short-term drilling rig and certain field equipment. During the three months ended March 31, 2019, costs from the Company’s frac fleets were also included in this amount, which is seen in the nine months ended September 30, 2019. Subsequent to March 31, 2019, the Company determined that the frac fleets are considered to have a term of one month or less and are no longer included in the short-term lease cost disclosure.

(3) Variable lease costs were not included in the measurement of the Company’s lease balances and primarily relate to common area maintenance charges on the Company’s corporate headquarters.

In accordance with the Company’s accounting policies, the Company’s share of these lease costs was either capitalized to oil and natural gas properties, or recorded within either general and administrative or lease operating expenses.

Lease Maturities

The table below reconciles the undiscounted lease payment maturities to the lease liabilities for the Company’s operating leases as of September 30, 2019:

	Remainder		Payments Due by Period for the Year Ending December 31,
(in thousands)	of 2019		2020		2021		2022		2023		Thereafter		Total
Operating lease payments (1)	$	9,450	$	33,428	$	1,547	$	1,558	$	1,589	$	7,378	$	54,950
Less: amount of lease payments representing interest													(3,168		)
Present value of future minimum lease payments													51,782
Less: current operating lease liabilities													(36,263		)
Long-term operating lease liabilities													$	15,519

(1) The operating lease payments represent the total payment obligation to be incurred over the remaining life of the lease. A portion of these costs will be billed to the Company’s working interest partners when the payment is incurred based on the nature of the cost and the relative working interest of the working interest partner.

19

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

Supplemental Lease Information

Supplemental information related to the Company’s operating leases was as follows:

	September 30, 2019
Weighted average remaining lease term - operating leases (in years)	2.8
Weighted average discount rate - operating leases (1)	4.2	%

(1) Upon adoption of the new lease standard, discount rates used for existing leases were established at January 1, 2019.

As of September 30, 2019, the Company has an additional lease that has not yet commenced related to additional office space for our corporate headquarters. The new lease is expected to commence in the first quarter of 2020, has a remaining lease term of 3.7 years and expected cash payments of $1.5 million.

As described in Note 2, Significant Accounting Policies and Related Matters, the Company adopted ASU 2016-02 using the modified retrospective approach as permitted under ASU 2018-11. This ASU also requires entities electing this transition method to provide the required disclosures under ASC 840 for all periods that continue to be presented in accordance with ASC 840. As such, the Company included the future minimum payments for noncancelable operating leases as of December 31, 2018, in accordance with ASC 840, as follows:

(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

In addition, lease payments associated with these operating leases were $0.5 million and $1.8 million for the three and nine months ended September 30, 2018, respectively.

Note 11—Commitments and Contingencies

Commitments

There were no material changes in commitments during the first nine months of 2019. Please refer to Note 10, Commitments and Contingencies, in the 2018 Form 10-K for additional discussion.

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 any such current 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 September 30, 2019 and December 31, 2018, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Note 12—Related Party Transactions

As a result of Quantum’s significant ownership interest in the Company, the Company identified Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”) and Phoenix Lease Services, LLC (“Phoenix”) as related parties. These entities are considered related parties as Quantum owns an interest, either directly or indirectly, in each entity.

20

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

During the second quarter of 2019, Quantum sold its interest in Oryx, at which point Oryx ceased to be a related party. As a result, transactions with Oryx that occurred subsequent to the date of sale are no longer considered related party transactions and are not included in the below disclosures.

The following table summarizes fees paid to Oryx and Phoenix for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Oryx via 3rd party shipper (1)	$	—	$	6,435	$	14,041	$	16,719
Oryx (2)	$	32	$	140	$	548	$	440
Phoenix (3)	$	17	$	98	$	68	$	319

(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 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 balance sheets. The Company also received $45 thousand from Oryx during the nine months ended September 30, 2019 related to pipeline easements and right of way agreements.

(3) Fees paid to Phoenix are capitalized to proved properties on the consolidated balance sheets.

At September 30, 2019 the Company had no outstanding payables to these related parties. At December 31, 2018, the Company had outstanding payables of $2.6 million to these related parties. See Note 11, Related Party Transactions, in the 2018 Form 10-K for more information.

Note 13—Subsequent Events

Proposed Merger of Jagged Peak with Parsley Energy, Inc.

On October 14, 2019, Jagged Peak entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Parsley Energy, Inc., a Delaware corporation (“Parsley”), and Jackal Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of Parsley (“Merger Sub”).

The closing of the Merger (as defined below) is expected to occur in the first quarter of 2020.

The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (1) Merger Sub will merge with and into Jagged Peak (the “Merger”), with Jagged Peak surviving the Merger as a wholly owned subsidiary of Parsley organized under the laws of the State of Delaware (the “Surviving Corporation”) and (2) following the Merger, the Surviving Corporation will merge with and into wholly owned limited liability company subsidiary of Parsley organized under the laws of the State of Delaware (“LLC Sub” and such merger, the “LLC Sub Merger”), with LLC Sub continuing as the surviving entity in the LLC Sub Merger and a wholly owned subsidiary of Parsley.

On the terms and subject to the conditions set forth in the Merger Agreement, upon consummation of the Merger, each share of Jagged Peak common stock, par value $0.01 per share, issued and outstanding immediately prior to the effective time of the Merger (excluding certain Excluded Shares and Non-Cancelled Shares (each, as defined in the Merger Agreement)) shall be converted into the right to receive from Parsley 0.447 fully-paid and non-assessable shares of Class A common stock, par value $0.01 per share, of Parsley (“Parsley Class A common stock”), with cash to be paid in lieu of fractional shares. Parsley’s Class A common stock is listed and trades on the New York Stock Exchange (the “NYSE”) under the ticker symbol PE.

The completion of the Merger is subject to certain customary mutual conditions, including (i) the receipt of the required approvals from Jagged Peak’s and Parsley’s stockholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act and any other applicable antitrust laws, (iii) the absence of any governmental order or law that makes consummation of the Merger illegal or otherwise prohibited, (iv) Parsley’s registration statement on Form S-4 (the “Form S-4”) having been declared effective by the U.S. Securities and Exchange Commission (“SEC”) under the Securities Act of 1933, (v) Parsley Class A common stock issuable in connection with the Merger having been authorized for listing on the NYSE, upon official notice of issuance, and (vi) the receipt by each party of a customary opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the U.S. tax code. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the Merger Agreement.

The Merger Agreement contains termination rights for each of Jagged Peak and Parsley, including, among others, if the consummation of the Merger does not occur on or before May 14, 2020. Upon termination of the Merger Agreement under specified circumstances, Jagged Peak may be required to pay Parsley a termination fee equal to $57.4 million or transaction

21

JAGGED PEAK ENERGY INC.

Notes to Consolidated Financial Statements

(Unaudited)

expenses of $16.4 million. Upon termination of the Merger Agreement under specified circumstances, Parsley may be required to pay the Company a termination fee equal to $189.0 million or transaction expenses of $54.0 million.

On November 4, 2019, Parsley filed the Form S-4 to register the Parsley shares to be issued in the Merger. The Form S-4 is subject to review by the SEC, and Parsley may file one or more amendments to the Form S-4 in the future.

Additional information on the proposed Merger, including the Merger Agreement, is included in the Form 8-K/A filed with the SEC on October 15, 2019.

Waiver to Redetermination Scheduled On or Around October 1, 2019

Due to the pending Merger of the Company with Parsley, the Company received a waiver for the redetermination of the borrowing base of the Amended and Restated Credit Facility that was scheduled to occur on or around October 1, 2019. Based on the terms of the waiver, the Company’s next borrowing base redetermination is scheduled to occur by February 15, 2020.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes presented in this Quarterly Report on Form 10-Q as well as our audited consolidated and combined financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2018. The following discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual obligations. Additionally, the discussion and analysis contains forward-looking statements, including, without limitation, statements related to our future plans, estimates, beliefs and expected performance. Please see “Cautionary Statement Concerning Forward-Looking Statements” in this Quarterly Report on Form 10-Q and “Part 1, Item 1A. Risk Factors” in our 2018 Form 10-K and this Quarterly Report on Form 10-Q.

In this section, references to “Jagged Peak,” “the Company,” “we,” “us” and “our” refer to Jagged Peak Energy Inc. and its subsidiaries, Jagged Peak Energy LLC (“JPE LLC”).

Overview

We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves. Our operations are entirely located in the United States, within the Permian Basin of West Texas. Our primary area of focus is the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin. Our acreage is located on large, contiguous blocks in the adjacent Texas counties of Winkler, Ward, Reeves and Pecos, with significant original oil-in-place within multiple stacked hydrocarbon-bearing formations. At September 30, 2019, our acreage position was approximately 77,200 net acres.

Summary of Operating and Financial Results for the Nine Months Ended September 30, 2019

• Brought online 48 gross (40.5 net) wells;

• Increased average daily production from the first nine months of 2018 by 16% to 38,081 Boe/d, comprised of 76% oil;

• Grew oil production 14% to 29,073 barrels per day, natural gas production by 13% to 25.0 MMcf/d and NGL production by 32% to 4,836 barrels per day compared to the first nine months of 2018;

• Impacted by negative natural gas revenues as a result of low and/or negative natural gas prices and the effect of gathering and processing costs; and

• Recorded impairment expense of $32.8 million largely related to our Big Tex area and our current plan to not drill on certain of these leases before they expire.

Proposed Merger with Parsley Energy

On October 14, 2019, Jagged Peak entered into a Merger Agreement with Parsley Energy, Inc., a Delaware corporation (“Parsley”), and Jackal Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of Parsley (“Merger Sub”). Pursuant to the Merger Agreement, Merger Sub will merge with and into Jagged Peak (the “Merger”), with Jagged Peak surviving the Merger as a wholly owned subsidiary of Parsley organized under the laws of the State of Delaware (the “Surviving Corporation”). Following the Merger, the Surviving Corporation will merge with and into a wholly owned limited liability company subsidiary of Parsley organized under the laws of the State of Delaware (“LLC Sub” and such merger, the “LLC Sub Merger”), with LLC Sub continuing as the surviving entity in the LLC Sub Merger and a wholly owned subsidiary of Parsley.

Under the terms of the Merger Agreement, each issued and outstanding eligible share of our common stock will be converted into the right to receive 0.447 of a share of Parsley Class A common stock (“Parsley Class A common stock”).

The closing of the Merger is expected to occur in the first quarter of 2020, subject to approvals from the stockholders of Jagged Peak and Parsley and certain other conditions. 

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See Note 13, Subsequent Events, in “Part I. Financial Information - Item 1. Financial Statements” for more information regarding the Merger.

Impact of Commodity Prices

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Increases or decreases in our revenue and profitability are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, infrastructure build-out, seasonality and geopolitical and economic factors.

The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX–WTI oil price or the NYMEX–Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. As of September 30, 2019, our oil production was sold based on prices established in Midland, Texas, and our natural gas production was effectively sold based on prices established at the Waha Hub in West Texas. These basis differentials can positively or negatively impact our oil and natural gas revenues.

For the three and nine months ended September 30, 2019 and 2018, our production revenues were derived from the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Oil sales	98	%	91	%	98	%	93	%
Natural gas sales	1	%	2	%	—	%	2	%
Natural gas liquids sales	1	%	7	%	2	%	5	%
Total (1)	100	%	100	%	100	%	100	%

(1) Our oil, natural gas and NGL revenues do not include the effects of derivatives.

The daily spot prices from published sources for Midland–WTI and for natural gas prices at the Waha Hub fluctuated compared to the corresponding NYMEX prices, as seen in the table below for the periods presented:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
Crude Oil (per Bbl):
Low NYMEX–WTI price	$	51.14		$	65.07	$	46.31		$	59.20
High NYMEX–WTI price	$	63.10		$	74.19	$	66.24		$	77.41
Low Midland–WTI price	$	50.69		$	48.01	$	41.09		$	48.01
High Midland–WTI price	$	63.20		$	66.37	$	63.20		$	66.91
Natural Gas (per Mcf):
Low NYMEX–Henry Hub price	$	2.02		$	2.73	$	2.02		$	2.49
High NYMEX–Henry Hub price	$	2.75		$	3.12	$	4.25		$	6.24
Low Waha Hub price	$	(0.16	)	$	0.81	$	(4.63	)	$	0.81
High Waha Hub price	$	1.93		$	2.51	$	3.27		$	7.27

Compared with the three and nine month periods of 2018, oil differentials have narrowed in the three and nine month periods of 2019 as a result of stabilization in the area and multiple pipelines that have been commissioned to resolve oil takeaway capacity issues.

The widening natural gas basis differentials during the three and nine months ended September 30, 2019 compared to the same periods in 2018 are largely attributable to the lack of sufficient pipeline takeaway capacity for oil and natural gas production in the Delaware Basin, primarily resulting from increased gas production in the area ahead of new pipelines commencing service. Additionally, the Waha Hub experienced a number of outages and maintenance projects impacting major pipelines in the area.

While we were adversely impacted by low or negative Waha prices during the first nine months of 2019, we have continued to produce our wells in order to sell oil, to meet lease and regulatory requirements and to sell the NGLs derived from processing the associated gas production. In addition to the low or negative price at the Waha Hub, the price we receive for our residue gas is affected by certain location, quality and other factors, as well as gathering and processing costs, as stipulated in our marketing agreements with purchasers.

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Index prices for various NGL components decreased during the three and nine months ended September 30, 2019 compared to the same periods of 2018. In addition to the index price, the prices we receive for our NGL components are affected by location, quality and other differentials, as well as gathering and processing costs.

The following table presents our average realized commodity prices, the effects of derivative settlements on our realized prices, the average daily NYMEX spot prices from published sources for oil and natural gas index prices, the average Midland–WTI oil spot price and the average Waha Hub natural gas spot price, for the periods presented:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Crude Oil (per Bbl):
Average realized price	$	53.55	$	55.95	$	52.52	$	59.15
Average realized price, including derivative settlements	$	52.29	$	53.45	$	50.67	$	54.30
Average NYMEX–WTI price	$	56.34	$	69.69	$	57.04	$	66.93
Average Midland–WTI price	$	56.07	$	55.25	$	55.85	$	59.21
Natural Gas (per Mcf):
Average realized price	$	0.31	$	1.19	$	0.13	$	1.29
Average NYMEX–Henry Hub price	$	2.38	$	2.93	$	2.62	$	2.95
Average Waha Hub price	$	0.94	$	1.89	$	0.78	$	2.10
NGLs (per Bbl):
Average realized price	$	3.47	$	24.81	$	6.58	$	23.71

See “Results of Operations” below for an analysis of the impact changes in realized prices had on our revenues.

Derivative Activity

To reduce the volatility of commodity prices, we enter into derivative instrument contracts which provide increased certainty of cash flows for funding our drilling program and debt service requirements.

As of September 30, 2019, we entered into the following derivative contracts:

Contract Period	Volumes (MBbls)	Wtd Avg Price ($/Bbl)
Oil Swaps (entered into as of September 30, 2019): ¹
October 1, 2019 through December 31, 2020	9,252	$	58.60
Oil Basis Swaps (entered into as of September 30, 2019): ²
October 1, 2019 through December 31, 2020	11,816	$	(1.98	)

(1) The index prices for the oil swaps are based on the NYMEX–WTI (Cushing, OK) monthly average futures price.

(2) The oil basis swap differential price is between Cushing–WTI and Midland–WTI.

During the nine months ended September 30, 2019, we incurred net payments of $14.7 million related to derivative agreements that settled during this time. We do not currently hedge price risk on any of our natural gas or NGL production, but, in the future, we may seek to hedge such production. See Note 3, Derivative Instruments, in “Part I. Financial Information - Item 1. Financial Statements” and “Item 3—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our derivative instruments, exposure to market risk and the effects of changes in commodity prices.

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Results of Operations

Comparison of the three months ended September 30, 2019 versus September 30, 2018

Revenues

Oil and Natural Gas Revenues.    The following table provides the components of our revenues for the three months ended September 30, 2019 and 2018, as well as each period’s respective average realized prices and production volumes:

	Three Months Ended September 30,
(in thousands or as indicated)	2019		2018		Change			% Change
Production revenues:
Oil sales	$	147,710	$	141,598	$	6,112		4	%
Natural gas sales	727		2,552		(1,825		)	(72	)%
NGL sales	1,628		10,814		(9,186		)	(85	)%
Total production revenues	$	150,065	$	154,964	$	(4,899	)	(3	)%
Average realized price: (1)
Oil (per Bbl)	$	53.55	$	55.95	$	(2.40	)	(4	)%
Natural gas (per Mcf)	$	0.31	$	1.19	$	(0.88	)	(74	)%
NGLs (per Bbl)	$	3.47	$	24.81	$	(21.34	)	(86	)%
Total (per Boe)	$	41.51	$	46.64	$	(5.13	)	(11	)%
Production volumes:
Oil (MBbls)	2,758		2,531		227			9	%
Natural gas (MMcf)	2,331		2,139		192			9	%
NGLs (MBbls)	469		436		33			8	%
Total (MBoe)	3,616		3,323		293			9	%
Average daily production volume:
Oil (Bbls/d)	29,980		27,507		2,473			9	%
Natural gas (Mcf/d)	25,339		23,245		2,094			9	%
NGLs (Bbls/d)	5,096		4,738		358			8	%
Total (Boe/d)	39,299		36,118		3,181			9	%

(1) Average prices shown in the table do not include settlements of commodity derivative transactions.

As reflected in the table above, our total production revenue for the three months ended September 30, 2019 was 3%, or $4.9 million, lower than that of the same period from 2018. The decrease is due to lower realized commodity prices, partially offset by higher sales volumes during the three months ended September 30, 2019. Our aggregate production volumes in the three months ended September 30, 2019 were 3,616 MBoe, comprised of 76% oil, 11% natural gas and 13% NGLs. This represents an increase of 9% over aggregate production volumes of 3,323 MBoe during the three months ended September 30, 2018.

The following table reconciles the change in oil, natural gas and NGL sales by reflecting the effect of changes in volumes and in the underlying commodity prices, from the three months ended September 30, 2018 to the three months ended September 30, 2019:

(in thousands)	Oil sales (1)			Natural gas sales (1)			NGL sales (1)			Total (1)
Three months ended September 30, 2018	$	141,598		$	2,552		$	10,814		$	154,964
Changes due to:
Increase (decrease) in production volumes	12,732			226			819			13,777
Increase (decrease) in average realized prices (2)	(6,620		)	(2,051		)	(10,005		)	(18,676		)
Three months ended September 30, 2019	$	147,710		$	727		$	1,628		$	150,065

(1) The net dollar effect of the increases in production is calculated as the change in period-to-period volumes for oil, natural gas and NGLs multiplied by the prior period average prices. The net dollar effect of the changes in prices is calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and NGLs.

(2) Natural gas and NGL revenues include gathering and processing costs. For the three months ended September 30, 2019 and 2018, these costs reduced our natural gas revenues by $0.9 million and $1.1 million, respectively, and reduced our NGL prices by $3.8 million and $3.6 million, respectively.

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Operating Expenses

The following table summarizes our operating expenses for the periods indicated:

	Three Months Ended September 30,									Per Boe
(in thousands, except per Boe)	2019		2018		Change			% Change		2019		2018
Lease operating expenses	$	17,554	$	11,184	$	6,370		57	%	$	4.85	$	3.37
Production and ad valorem taxes	11,263		9,517		1,746			18	%	$	3.11	$	2.86
Exploration	3		23		(20		)	(87	)%	$	—	$	0.01
Depletion, depreciation, amortization and accretion	66,069		57,660		8,409			15	%	$	18.27	$	17.35
Impairment of unproved oil and natural gas properties	31,817		—		31,817			NM		NM		NM
Other operating expenses	—		19		(19		)	(100	)%	$	—	$	0.01
General and administrative (before equity-based compensation)	9,571		9,707		(136		)	(1	)%	$	2.65	$	2.92
Total operating expenses (before equity-based compensation)	136,277		88,110		48,167			55	%	$	37.69	$	26.52
Equity-based compensation	4,098		2,614		1,484
Total operating expenses	$	140,375	$	90,724	$	49,651

NM A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200. A per Boe calculation is not meaningful as the underlying expense does not correspond to changes in production.

Lease Operating Expenses.    Lease operating expense (“LOE”) increased to $17.6 million in the three months ended September 30, 2019, compared to $11.2 million for the same period of 2018. The increase largely corresponds to $7.5 million of workover expense in the three months ended September 30, 2019, an increase of $4.1 million compared to the same period of 2018. Additionally, during the three months ended September 30, 2019, our production and well counts increased between periods, resulting in overall higher costs for contract labor, equipment, chemicals and electricity. LOE per Boe increased 44% to $4.85 for the three months ended September 30, 2019, as compared to the same period of 2018, primarily due to increased costs for workovers, contract labor and chemicals.

Production and Ad Valorem Taxes.    Production and ad valorem taxes were $11.3 million for the three months ended September 30, 2019, an increase of $1.7 million, or 18%, from $9.5 million for the three months ended September 30, 2018. The increase is due to increased ad valorem taxes, which resulted from the addition of multiple new high-volume wells. This was partially offset by a slight decrease in production taxes that resulted from the decrease in revenues.

Depletion, Depreciation, Amortization and Accretion.    The components of depletion, depreciation, amortization and accretion (“DD&A”) expense for the three months ended September 30, 2019 and 2018 are summarized as follows:

	Three Months Ended September 30,				Per Boe
(in thousands)	2019		2018		2019		2018
Depletion of oil and natural gas properties	$	65,569	$	57,170	$	18.13	$	17.20
Depreciation of other property and equipment	437		459		$	0.12	$	0.14
Accretion of asset retirement obligations	63		31		$	0.02	$	0.01
Depletion, depreciation, amortization and accretion	$	66,069	$	57,660	$	18.27	$	17.35

Depletion of oil and natural gas properties increased $8.4 million during the three months ended September 30, 2019 compared to the same period of 2018 due to higher production and an increase in our depletion rate. Our depletion rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The depletion rate per Boe increased 5% to $18.13 per Boe during the three months ended September 30, 2019, compared to $17.20 per Boe for the three months ended September 30, 2018. The increase in our depletion rate per Boe was largely due to an increase in capitalized costs, while the rate of increase in reserve volumes related to those drilling activities was lower than the rate of capital cost increase.

Impairment of Unproved Oil and Natural Gas Properties.    We incurred $31.8 million of impairment expense during the three months ended September 30, 2019, compared to none during the same period of 2018. The impairments during the three months ended September 30, 2019 were largely related to certain acreage within our Big Tex area, and our current plan to not drill on certain of these leases before they expire. No impairments were recorded on proved properties during the three months ended September 30, 2019 and 2018.

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General and Administrative and Equity-based Compensation.    General and administrative expenses (“G&A”), excluding equity-based compensation, decreased 1% to $9.6 million for the three months ended September 30, 2019, from $9.7 million for the same period of 2018.

Equity-based compensation expense for the three months ended September 30, 2019 and 2018 is summarized as follows:

	Three Months Ended September 30,
(in thousands)	2019		2018		Change
Incentive unit awards	$	856	$	609	$	247
Restricted stock unit awards	1,839		989		850
Performance stock unit awards	1,403		1,016		387
Equity-based compensation expense	$	4,098	$	2,614	$	1,484

For additional information regarding our equity-based compensation, see Note 5, Equity-based Compensation, in “Part I. Financial Information - Item 1. Financial Statements.”

Other Income and Expense

The following table summarizes our other income and expenses for the periods indicated:

	Three Months Ended September 30,
(in thousands)	2019			2018			Change
Gain (loss) on commodity derivatives	$	39,421		$	(96,516	)	$	135,937
Interest expense, net	(9,974		)	(8,256		)	(1,718		)
Gain on sale of oil and natural gas properties	—			6,225			(6,225		)
Other, net	18			12			6
Total other income (expense)	$	29,465		$	(98,535	)	$	128,000

Gain (loss) on Commodity Derivatives.    We utilize commodity derivative instruments to reduce our exposure to fluctuations in commodity prices. This amount includes (i) the gain (loss) related to derivative contracts that have settled within the period and (ii) the gain (loss) related to fair value adjustments on our open derivative contracts. The following table sets forth these components for the three months ended September 30, 2019 and 2018:

	Three Months Ended September 30,
(in thousands)	2019			2018
Net gain (loss) on settled derivative instruments	$	(3,484	)	$	(6,347	)
Net gain (loss) from the change in fair value of open derivative instruments	42,905			(90,169		)
Gain (loss) on commodity derivatives	$	39,421		$	(96,516	)

To the extent the future commodity price outlook declines between measurement periods, we will generally have noncash mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will generally have noncash mark-to-market losses. See Note 3, Derivative Instruments, and Note 9, Fair Value Measurements, in “Part I. Financial Information - Item 1. Financial Statements” for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.

Interest Expense, net.    The following table summarizes our interest expense for the three months ended September 30, 2019 and 2018:

	Three Months Ended September 30,
(in thousands)	2019			2018
Amended and Restated Credit Facility (1)	$	2,249		$	491
Senior Notes	7,343			7,322
Amortization of debt issuance costs (2)	594			732
Capitalized interest	(212		)	(289		)
Interest expense, net	$	9,974		$	8,256

(1) Includes interest on outstanding balances and commitment fees on undrawn balances.

(2) Includes amortization of debt issuance costs on the Amended and Restated Credit Facility and Senior Notes.

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The increase in interest expense on the Amended and Restated Credit Facility is due to an increase in our weighted average credit facility outstanding of $187.1 million during the three months ended September 30, 2019, compared to no borrowings during the same period of 2018.

Gain on Sale of Assets.    The $6.2 million gain on sale of assets in the three months ended September 30, 2018 related to the sale of non-core unproved acreage.

Income tax expense (benefit)

During the three months ended September 30, 2019, we had income tax expense of $8.6 million, compared to a benefit of $7.3 million for the same period of 2018. The change is primarily due to net income in the three months ended September 30, 2019 compared to a net loss for the same period of 2018.

Comparison of the nine months ended September 30, 2019 versus September 30, 2018

Revenues

Oil and Natural Gas Revenues.    The following table provides the components of our revenues for the nine months ended September 30, 2019 and 2018, as well as each period’s respective average realized prices and production volumes:

	Nine Months Ended September 30,
(in thousands or as indicated)	2019		2018		Change			% Change
Production revenues:
Oil sales	$	416,824	$	410,935	$	5,889		1	%
Natural gas sales	904		7,765		(6,861		)	(88	)%
NGL sales	8,680		23,721		(15,041		)	(63	)%
Total production revenues	$	426,408	$	442,421	$	(16,013	)	(4	)%
Average realized price: (1)
Oil (per Bbl)	$	52.52	$	59.15	$	(6.63	)	(11	)%
Natural gas (per Mcf)	$	0.13	$	1.29	$	(1.16	)	(90	)%
NGLs (per Bbl)	$	6.58	$	23.71	$	(17.13	)	(72	)%
Total (per Boe)	$	41.02	$	49.42	$	(8.40	)	(17	)%
Production volumes:
Oil (MBbls)	7,937		6,947		990			14	%
Natural gas (MMcf)	6,834		6,025		809			13	%
NGLs (MBbls)	1,320		1,001		319			32	%
Total (MBoe)	10,396		8,952		1,444			16	%
Average daily production volume:
Oil (Bbls/d)	29,073		25,447		3,626			14	%
Natural gas (Mcf/d)	25,034		22,069		2,965			13	%
NGLs (Bbls/d)	4,836		3,665		1,171			32	%
Total (Boe/d)	38,081		32,790		5,291			16	%

(1) Average prices shown in the table do not include settlements of commodity derivative transactions.

As reflected in the table above, our total production revenue for the nine months ended September 30, 2019 was 4%, or $16.0 million, lower than that of the same period from 2018. The decrease is due to lower realized commodity prices, partially offset by higher sales volumes, during the nine months ended September 30, 2019. Our aggregate production volumes in the nine months ended September 30, 2019 were 10,396 MBoe, comprised of 76% oil, 11% natural gas and 13% NGLs. This represents an increase of 16% over aggregate production volumes of 8,952 MBoe during the nine months ended September 30, 2018.

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The following table reconciles the change in oil, natural gas and NGL sales by reflecting the effect of changes in volumes and in the underlying commodity prices, from the nine months ended September 30, 2018 to the nine months ended September 30, 2019:

(in thousands)	Oil sales (1)			Natural gas sales (1)			NGL sales (1)			Total (1)
Nine months ended September 30, 2018	$	410,935		$	7,765		$	23,721		$	442,421
Changes due to:
Increase (decrease) in production volumes	58,511			1,067			7,573			67,151
Increase (decrease) in average realized prices (2)	(52,622		)	(7,928		)	(22,614		)	(83,164		)
Nine months ended September 30, 2019	$	416,824		$	904		$	8,680		$	426,408

(1) The net dollar effect of the increases in production is calculated as the change in period-to-period volumes for oil, natural gas and NGLs multiplied by the prior period average prices. The net dollar effect of the changes in prices is calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and NGLs.

(2) Natural gas and NGL revenues include gathering and processing costs. For the nine months ended September 30, 2019 and 2018, these costs reduced our natural gas revenues by $3.1 million and $3.0 million, respectively, and reduced our NGL revenues by $11.3 million and $8.2 million, respectively.

Operating Expenses

The following table summarizes our operating expenses for the periods indicated:

	Nine Months Ended September 30,									Per Boe
(in thousands, except per Boe)	2019		2018		Change			% Change		2019		2018
Lease operating expenses	$	46,758	$	31,390	$	15,368		49	%	$	4.50	$	3.51
Production and ad valorem taxes	32,100		26,437		5,663			21	%	$	3.09	$	2.95
Exploration	3		24		(21		)	(88	)%	$	—	$	—
Depletion, depreciation, amortization and accretion	186,365		160,552		25,813			16	%	$	17.93	$	17.93
Impairment of unproved oil and natural gas properties	32,763		53		32,710			NM		NM		NM
Other operating expenses	3,206		65		3,141			NM		$	0.31	$	0.01
General and administrative (before equity-based compensation)	29,116		28,800		316			1	%	$	2.80	$	3.22
Total operating expenses (before equity-based compensation)	330,311		247,321		82,990			34	%	$	31.77	$	27.63
Equity-based compensation	11,025		80,671		(69,646		)
Total operating expenses	$	341,336	$	327,992	$	13,344

NM A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200. A per Boe calculation is not meaningful as the underlying expense does not correspond to changes in production.

Lease Operating Expenses.    LOE increased to $46.8 million in the nine months ended September 30, 2019, compared to $31.4 million for the same period of 2018. The increase largely corresponds to $17.9 million of workover expense, an increase of $7.4 million compared to the same period of 2018. Additionally, during the nine months ended September 30, 2019, our production and well counts increased between periods, resulting in overall higher costs for contract labor, equipment, equipment rentals and electricity. LOE per Boe increased $0.99 to $4.50 for the nine months ended September 30, 2019, as compared to the same period of 2018, primarily due to increased costs on workovers, contract labor, equipment and chemicals.

Production and Ad Valorem Taxes.    Production and ad valorem taxes were $32.1 million for the nine months ended September 30, 2019, an increase of $5.7 million, or 21%, from $26.4 million for the nine months ended September 30, 2018. The increase was due to increased ad valorem taxes from the addition of multiple new high-volume wells, partially offset by a decrease in production taxes due to a decrease in revenues.

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Depletion, Depreciation, Amortization and Accretion.    The components of DD&A expense for the nine months ended September 30, 2019 and 2018 are summarized as follows:

	Nine Months Ended September 30,				Per Boe
(in thousands)	2019		2018		2019		2018
Depletion of oil and natural gas properties	$	184,928	$	158,975	$	17.79	$	17.76
Depreciation of other property and equipment	1,278		1,490		$	0.12	$	0.16
Accretion of asset retirement obligations	159		87		$	0.02	$	0.01
Depletion, depreciation, amortization and accretion	$	186,365	$	160,552	$	17.93	$	17.93

Depletion of oil and natural gas properties increased $26.0 million during the nine months ended September 30, 2019 compared to the same period of 2018 primarily due to higher production and a slight increase in our depletion rate. Our depletion rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The depletion rate per Boe increased $0.03 to $17.79 per Boe during the nine months ended September 30, 2019, compared to $17.76 per Boe for the nine months ended September 30, 2018.

Impairment of Unproved Oil and Natural Gas Properties.    We incurred $32.8 million of impairment expense during the nine months ended September 30, 2019, compared to $0.1 million during the same period of 2018. The impairments in 2019 were largely related to certain acreage within our Big Tex area, and our current plan to not drill on certain of these leases before they expire. The impairments in 2018 were due to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties during the nine months ended September 30, 2019 or 2018.

Other Operating Expenses.    The $3.2 million of other operating expenses for the nine months ended September 30, 2019 was related to the early termination of a frac fleet contract in the first quarter of 2019.

General and Administrative and Equity-based Compensation.    G&A, excluding equity-based compensation, increased 1% to $29.1 million for the nine months ended September 30, 2019, from $28.8 million for the same period of 2018. The slight increase is primarily due to increased personnel costs, including salaries, employee benefits and contract personnel. These increases were partially offset by a $2.8 million decrease related to severance and other nonrecurring expenses from the first quarter of 2018. The number of full-time employees increased from 80 at September 30, 2018 to 109 at September 30, 2019.

Equity-based compensation expense for the nine months ended September 30, 2019 and 2018 is summarized as follows:

	Nine Months Ended September 30,
(in thousands)	2019		2018		Change
Incentive unit awards	$	2,050	$	75,767	$	(73,717	)
Restricted stock unit awards	4,988		3,391		1,597
Performance stock unit awards	3,987		1,513		2,474
Equity-based compensation expense	$	11,025	$	80,671	$	(69,646	)

The decrease in equity-based compensation expense for incentive unit awards is due to a modification of the service requirements in the first quarter of 2018, which resulted in an acceleration of the compensation expense for the awards allocated at the time of the IPO. The remaining incentive unit award expense relates to awards allocated after the IPO.

The increase in equity-based compensation expense for PSU awards is primarily due to the nine month-period ended September 30, 2018 reflecting the reversal of equity-based compensation expense, which related to forfeited PSU awards by former executive officers. As the Company’s policy is to recognize forfeitures as they occur, previously recognized expense on unvested awards is reversed at the date of forfeiture.

For additional information regarding our equity-based compensation, see Note 5, Equity-based Compensation, in “Part I. Financial Information - Item 1. Financial Statements.”

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Other Income and Expense

The following table summarizes our other income and expenses for the periods indicated:

	Nine Months Ended September 30,
(in thousands)	2019			2018			Change
Gain (loss) on commodity derivatives	$	(85,702	)	$	(110,426	)	$	24,724
Interest expense, net	(27,683		)	(17,095		)	(10,588		)
Gain on sale of oil and natural gas properties	—			6,225			(6,225		)
Other, net	(105		)	30			(135		)
Total other income (expense)	$	(113,490	)	$	(121,266	)	$	7,776

Gain (loss) on Commodity Derivatives.    We utilize commodity derivative instruments to reduce our exposure to fluctuations in commodity prices. This amount includes (i) the gain (loss) related to derivative contracts that have settled within the period and (ii) the gain (loss) related to fair value adjustments on our open derivative contracts. The following table sets forth these components for the nine months ended September 30, 2019 and 2018:

	Nine Months Ended September 30,
(in thousands)	2019			2018
Net gain (loss) on settled derivative instruments	$	(14,651	)	$	(33,705	)
Net gain (loss) from the change in fair value of open derivative instruments	(71,051		)	(76,721		)
Gain (loss) on commodity derivatives	$	(85,702	)	$	(110,426	)

To the extent the future commodity price outlook declines between measurement periods, we will generally have noncash mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will generally have noncash mark-to-market losses. See Note 3, Derivative Instruments, and Note 9, Fair Value Measurements, in “Part I. Financial Information - Item 1. Financial Statements” for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.

Interest Expense, net.    The following table summarizes our interest expense for the nine months ended September 30, 2019 and 2018:

	Nine Months Ended September 30,
(in thousands)	2019			2018
Amended and Restated Credit Facility (1)	$	4,566		$	4,528
Senior Notes	22,031			11,668
Amortization of debt issuance costs (2)	1,770			1,753
Capitalized interest	(684		)	(854		)
Interest expense, net	$	27,683		$	17,095

(1) Includes interest on outstanding balances and commitment fees on undrawn balances.

(2) Includes amortization of debt issuance costs on the Amended and Restated Credit Facility and Senior Notes.

The increase in total interest expense during the nine months ended September 30, 2019 is associated with the issuance of the Senior Notes in May 2018.

Gain on Sale of Assets.    The $6.2 million gain on sale of assets in the nine months ended September 30, 2018 related to the sale of non-core unproved acreage.

Income tax expense (benefit)

During the nine months ended September 30, 2019, we had an income tax benefit of $6.0 million, compared to an expense of $14.7 million for the same period of 2018. The change is primarily due to a higher net loss in the first nine months of 2019 compared to the first nine months of 2018. Income tax expense in the first nine months of 2018 primarily resulted from equity-based compensation expense related to incentive unit awards that were allocated at the time of the IPO, which was not deductible for federal or state income tax purposes.

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Capital Commitments, Capital Resources and Liquidity

Capital Commitments

Our primary needs for cash relate to the development and exploration of our oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, borrowings under our Amended and Restated Credit Facility, joint venture partnerships, water system financings, asset sales, offerings of debt and equity securities or other means.

2019 Capital Budget

Our 2019 capital budget for development of oil and gas properties and infrastructure is as follows:

(in millions)
Drilling and completion	$	580.0	—	$	630.0
Water infrastructure	25.0		—	35.0
Total	$	605.0	—	$	665.0

Our 2019 capital budget excludes potential leasehold and/or surface acreage additions. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

Because we operate a high percentage of our acreage, capital expenditure amounts and timing are largely discretionary and within our control. We determine our capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling obligations, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if we curtail or reallocate priorities in our drilling program, we may lose a portion of our acreage through lease expirations. Furthermore, we may be required to remove some portion of our reserves currently booked as proved undeveloped if such changes in planned capital expenditures mean we will be unable to develop such reserves within five years of their initial booking.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and additional borrowing capacity under our Amended and Restated Credit Facility to execute our remaining 2019 capital program and anticipated 2020 capital expenditures. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. If we require additional capital funding for capital expenditures, acquisitions or other reasons, we may seek such capital through borrowings under our Amended and Restated Credit Facility, joint venture partnerships, water system financings, asset sales, offerings of debt and equity securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our planned drilling program. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

Capital Expenditures

Capital expenditures for oil and gas acquisitions, exploration, development and infrastructure activities are summarized below:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Acquisitions
Proved properties	$	375	$	—	$	7,782	$	—
Unproved properties (1)	17,316		7,575		25,295		18,670
Development costs	162,571		151,797		451,261		535,590
Infrastructure costs	4,520		5,439		25,678		13,440
Exploration costs	3		23		3		24
Total oil and gas capital expenditures	$	184,785	$	164,834	$	510,019	$	567,724

(1) Relates to oil and natural gas mineral interest leasing and renewal activity.

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For the nine months ended September 30, 2019 and 2018, our capital expenditures have been focused on the development of our properties in the southern Delaware Basin, as seen in the table below showing newly producing wells. As of September 30, 2019, we had approximately 87,300 gross (77,200 net) acres.

The following table reflects wells that began producing in the periods indicated:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Gross wells
Operated	17	10	40	36
Non-operated	8	1	8	13
	25	11	48	49
Net wells
Operated	16.2	9.8	38.4	33.5
Non-operated	2.1	0.1	2.1	5.1
	18.3	9.9	40.5	38.6

At September 30, 2019, we were in the process of drilling 12 gross (11.6 net) wells and had eight gross (8.0 net) wells that were in process of being completed.

Contractual Obligations

A summary of our contractual obligations as of September 30, 2019 is provided in the following table:

	Remainder		Payments Due by Period for the Year Ending December 31,
(in thousands)	of 2019		2020		2021		2022		2023		Thereafter		Total
Senior secured credit facility (1)	$	—	$	—	$	—	$	—	$	215,000	$	—	$	215,000
Senior notes—principal	—		—		—		—		—		500,000		500,000
Senior notes—interest (2)	14,688		29,375		29,375		29,375		29,375		73,437		205,625
Operating leases (3)	9,450		33,428		1,547		1,558		1,589		7,378		54,950
Service and purchase contracts (4)	10,305		15,514		3,706		3,633		3,633		13,926		50,717
Total	$	34,443	$	78,317	$	34,628	$	34,566	$	249,597	$	594,741	$	1,026,292

(1) This table does not include future commitment fees, interest expense or other costs related to our Amended and Restated Credit Facility because we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. As of September 30, 2019, we had $215.0 million outstanding under our Amended and Restated Credit Facility. The borrowing base and elected commitments remained at $900.0 million and $540.0 million, respectively, and the Company had $325.0 million of elected commitments available.

(2) Interest represents the scheduled cash payments on the Senior Notes.

(3) Relates to lease payment maturities for our operating leases, which include drilling rigs, our corporate headquarters and certain office equipment. See Note 10, Leases, in “Part I. Financial Information - Item 1. Financial Statements” for more information on our operating leases.

(4) Primarily relates to a casing and tubing purchase agreement, a coiled tubing service agreement and a retail power purchase agreement.

Additionally, in 2018 the Company entered into a 5-year oil marketing agreement that became effective on October 1, 2019 and links 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.

Off-Balance Sheet Arrangements

We had no material off balance sheet arrangements as of September 30, 2019. Please read Note 11, Commitments and Contingencies, in “Part I. Financial Information - Item 1. Financial Statements” for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

Capital Resources and Liquidity

Historically, our primary capital resources and liquidity were capital contributions from equity owners, including the IPO, proceeds from the Senior Notes offering, borrowings under our Amended and Restated Credit Facility and cash flows from operations. During the first nine months of 2019, our primary sources of liquidity were cash flows from operations of $272.7

33

million and borrowings on our Amended and Restated Credit Facility of $215.0 million. Our primary uses of cash have been the development and acquisition of oil and natural gas properties and the development of water sourcing and disposal infrastructure. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.

Based on our forecasted cash flows from operating activities and availability under our revolving credit facilities, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

	Nine Months Ended September 30,
(in thousands)	2019			2018
Net cash provided by operating activities	$	272,701		$	317,747
Net cash used in investing activities	$	(511,449	)	$	(564,781	)
Net cash provided by financing activities	$	214,122		$	331,450

Operating Activities.    Net cash provided by operating activities is primarily affected by production volumes, the price of oil, natural gas and NGLs, operating and general and administrative expenses and changes in working capital.

The $45.0 million decrease in the first nine months of 2019 compared to 2018 primarily resulted from lower realized commodity prices. We also experienced higher cash operating costs and interest expense.

Investing Activities.    Cash flows from investing activities primarily consist of the acquisition, exploration, and development of oil and natural gas properties, net of dispositions of oil and natural gas properties.

During the first nine months of 2019, net cash flow used in investing activities was $511.4 million, which included investments in developing our acreage and infrastructure of $477.7 million and leasehold and acquisition costs of $32.9 million. In the first nine months of 2018, net cash used for investing activities of $564.8 million included $551.1 million and $18.9 million for the development and acquisition of oil and natural gas properties, respectively.

Financing Activities.    Net cash provided by financing activities includes equity and debt transactions.

Net cash provided by financing activities during the first nine months of 2019 was due to $215.0 million of borrowings on our credit facility. Net cash provided by financing activities in the first nine months of 2018 was primarily due to $488.4 million of net proceeds from the Senior Notes offering, which was partially offset by a net repayment on our credit facility of $155.0 million.

Senior Secured Revolving Credit Facility

At December 31, 2018, the Amended and Restated Credit Facility had a borrowing base of $900.0 million, with nothing outstanding under the credit facility, and $540.0 million in unused borrowing capacity under our elected commitments. At September 30, 2019, the borrowing base and elected commitments remained at $900.0 million and $540.0 million, respectively, and we had $215.0 million outstanding and $325.0 million of elected commitments available. As of the date of this filing, the Company has $260.0 million outstanding and $280.0 million available under the Amended and Restated Credit Facility.

The amount available to be borrowed under our Amended and Restated Credit Facility is subject to a borrowing base that is subject to semiannual borrowing base redeterminations on or around each April 1 and October 1, of each year by the lenders at their sole discretion. Additionally, at our option, we may request up to two additional redeterminations per year, to be effective on or about January 1 and July 1. Due to the pending Merger of the Company with Parsley, our scheduled redetermination on or around October 1, 2019 was postponed to occur by February 15, 2020. Completion of the Merger would give rise to an event of default under the terms of the Amended and Restated Credit Facility. Pursuant to the terms of the Merger Agreement, Parsley will repay indebtedness outstanding under the Amended and Restated Credit Facility prior to consummation of the Merger.

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The Amended and Restated Credit Facility 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:

Financial Covenant	Required Ratio
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than	1.0	to	1.0
Ratio of debt to EBITDAX, as defined in the credit agreement	Not greater than	4.0	to	1.0

As of September 30, 2019, we were in compliance with all financial covenants.

Please read Note 4, Debt, in “Part I. Financial Information - Item 1. Financial Statements” for more information on our Amended and Restated Credit Facility.

Critical Accounting Policies and Estimates

Our management makes a number of significant estimates, assumptions and judgments in the preparation of our financial statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2018 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for impairment of oil and natural gas properties, oil, natural gas and NGL reserve quantities and standardized measure of discounted future net cash flows, derivative instruments, and income taxes. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to our consolidated financial statements contained in this Quarterly Report on Form 10-Q. The application of our critical accounting policies may require management to make judgments and estimates about the amounts reflected in the consolidated financial statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.

Recent Accounting Pronouncements

Please refer to Note 2, Significant Accounting Policies and Related Matters - Recent Accounting Pronouncements, in “Part I. Financial Information - Item 1. Financial Statements” for a discussion of recent accounting pronouncements and their anticipated effect on our business.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with “Item 7A. Qualitative and Quantitative Disclosures About Market Risk” contained in our 2018 Form 10-K.

Market risk refers to potential losses from adverse changes in market prices and rates. We are exposed to market risk primarily in the form of commodity price risk and interest rate risk. In order to manage exposure to commodity price risk, we use commodity derivative financial instruments, including swaps and basis swaps. Our objective is to reduce fluctuations in cash flows resulting from changes in commodity prices. We do not enter into derivative or other financial instruments for speculative trading purposes.

Hypothetical changes in commodity prices and interest rates chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has historically been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on numerous factors beyond our control.

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The following table shows how hypothetical changes in the realized prices we receive for our commodity sales would have impacted revenue for the nine months ended September 30, 2019:

				Sensitivity Analysis
(in thousands)	Revenue (1)		% of Total	Change in Realized Prices	Impact on Revenue
Oil	$	416,824	98%	+ / - 10% per barrel	+ / -	$	41,682
Natural gas	904		—%	+ / - 10% per Mcf	+ / -	$	90
NGL	8,680		2%	+ / - 10% per barrel	+ / -	$	868
Total	$	426,408	100%

(1) Our oil, natural gas and NGL revenues do not include the effects of derivatives instruments.

To reduce our exposure to changes in the prices of commodities, we have entered into commodity derivative instruments for a portion of our oil production for the remainder of 2019 and through 2020, and may in the future enter into additional commodity derivative instruments for a portion of our future oil production. The agreements entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil production over the contracted period of time. Our commodity derivative instruments are recorded at fair value and the changes to future commodity prices have an impact on net income. During the nine months ended September 30, 2019 we recorded a loss on derivatives of $85.7 million, compared to a loss of $110.4 million for the same period in 2018.

The fair value of our derivative instruments is determined based on valuation models. We did not change our valuation method for our derivative instruments during the nine months ended September 30, 2019.

The following table reconciles the changes that occurred in the fair values of our derivative instruments from December 31, 2018 to September 30, 2019:

	Commodity Derivative Instruments
(in thousands)	Net Assets (Liabilities)
Fair value of open contracts at December 31, 2018	$	100,621
Gain (loss) on commodity derivatives	(85,702		)
Net cash payments on settled derivatives	14,651
Fair value of open contracts at September 30, 2019	$	29,570

The following table sets forth the hypothetical impact on the fair value of our net oil derivative asset of $29.6 million as of September 30, 2019, using an average increase or decrease of 10% to the commodity prices:

	Change in Forward Commodity Prices
(in thousands)	10% Increase		10% Decrease
Increase (decrease) to net oil derivative asset as of September 30, 2019	$	48,253	$	(48,253	)

Our commodity derivative instruments allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. In the future, we may use commodity derivatives to hedge a portion of our natural gas or NGL production.

Our commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings and are all lenders, or affiliates of lenders, under our Amended and Restated Credit Facility.

See Note 3, Derivative Instruments, and Note 9, Fair Value Measurements, in “Part I. Financial Information - Item 1. Financial Statements” for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.

Interest Rate Risk

We are exposed to market risk related to changes in interest rates, which affects the amount of interest we pay on certain of our borrowings and the amount of interest we earn on our short-term investments.

As of September 30, 2019, we had no significant investments; therefore, we were not exposed to material interest rate risk on investments.

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As of September 30, 2019, we had approximately $705.3 million of long-term debt outstanding, net of unamortized debt issuance costs. Of this amount, $490.3 million was fixed-rate debt, net of unamortized debt issuance costs, with a fixed interest coupon rate of 5.875%. Although near term changes in interest rates may impact the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss.

The $215.0 million, as of September 30, 2019, outstanding under our Amended and Restated Credit Facility is subject to variable interest rates, which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. A change in the interest rate applicable to our variable-rate debt could expose us to additional interest cost. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $2.2 million per year.

We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. For additional information regarding our debt instruments, refer to Note 4, Debt, in “Part I. Financial Information - Item 1. Financial Statements.”

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2019. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2019 at the reasonable assurance level. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

Item 1A. Risk Factors

Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. In addition to the risk factors set forth below and the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

Set forth below are certain material changes to the Risk Factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018 due to the Company executing the Merger Agreement with Parsley:

Because the exchange ratio is fixed and because the market price of Parsley Class A common stock may fluctuate, our stockholders cannot be certain of the precise value of any merger consideration they may receive in the Merger.

At the time the Merger is completed, each issued and outstanding eligible share of our common stock will be converted into the right to receive the merger consideration of 0.447 of a share of Parsley Class A common stock. The exchange ratio for the merger consideration is fixed, and there will be no adjustment to the merger consideration for changes in the market price of Parsley Class A common stock or our common stock prior to the completion of the Merger. If the Merger is completed, there will be a time lapse between the date of signing the Merger Agreement and the date on which our stockholders who are entitled to receive the merger consideration actually receive the merger consideration. The market value of shares of Parsley Class A common stock may fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in Parsley’s businesses, operations and prospects and regulatory considerations. Such factors are difficult to predict and in many cases may be beyond the control of Parsley and us. The actual value of any merger consideration received by our stockholders at the completion of the Merger will depend on the market value of the shares of Parsley Class A common stock at that time. This market value may differ, possibly materially, from the market value of shares of Parsley Class A common stock at the time the Merger Agreement was entered into or at any other time. Our stockholders should obtain current stock quotations for shares of Parsley Class A common stock and for shares of our common stock.

The Merger may not be completed and the Merger Agreement may be terminated in accordance with its terms.

The Merger is subject to a number of conditions that must be satisfied or waived prior to the completion of the Merger, including the receipt of the required approvals from our and Parsley’s stockholders. These conditions to the completion of the Merger may not be satisfied or waived in a timely manner or at all, and, accordingly, the Merger may be delayed or may not be completed.

Moreover, if the Merger is not completed by May 14, 2020, either Parsley or Jagged Peak may choose not to proceed with the Merger, and the parties can mutually decide to terminate the Merger Agreement at any time, before or after stockholder approval. In addition, Parsley and Jagged Peak may elect to terminate the Merger Agreement in certain other circumstances as further detailed in the Merger Agreement.

Current Jagged Peak stockholders will have a reduced ownership and voting interest in Parsley after the Merger compared to their current ownership in Jagged Peak on a standalone basis and will exercise less influence over management.

Currently, Jagged Peak stockholders have the right to vote in the election of the Jagged Peak board of directors and on other matters requiring stockholder approval under Delaware law and the Jagged Peak articles of incorporation and bylaws. As a

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result of the Merger, current Jagged Peak stockholders will own a smaller percentage of Parsley than they currently own of Jagged Peak, and as a result will have less influence on the management and policies of Parsley after the Merger than they now have on the management and policies of Jagged Peak.

The Merger Agreement limits our ability to pursue alternatives to the Merger.

The Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the Merger, or may result in a potential competing acquirer of the Company proposing to pay a lower per share price to acquire the Company than it might otherwise have proposed to pay. These provisions include covenants by Jagged Peak not to solicit proposals relating to alternative transactions or, subject to certain exceptions, enter into discussions concerning or provide information in connection with alternative transactions and, subject to certain exceptions, to recommend that its stockholders approve and adopt the Merger Agreement.

Failure to complete the Merger could negatively impact the price of shares of our common stock, as well as our future businesses and financial results.

The Merger Agreement contains a number of conditions that must be satisfied or waived prior to the completion of the Merger. There can be no assurance that all of the conditions to the completion of the Merger will be so satisfied or waived. If these conditions are not satisfied or waived, we will be unable to complete the Merger.

If the Merger is not completed for any reason, including the failure to receive the required approval of our stockholders and Parsley’s stockholders, our businesses and financial results may be adversely affected, including as follows:

• we may experience negative reactions from the financial markets, including negative impacts on the market price of our common stock;

• the manner in which customers, vendors, business partners and other third parties perceive the Company may be negatively impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the marketplace more broadly;

• we will still be required to pay certain significant costs relating to the Merger, such as legal, accounting, financial advisor and printing fees;

• we may experience negative reactions from employees; and

• we will have expended time and resources that could otherwise have been spent on our existing businesses and the pursuit of other opportunities that could have been beneficial to the Company, and our ongoing business and financial results may be adversely affected.

In addition to the above risks, if the Merger Agreement is terminated and our board seeks an alternative transaction, our stockholders cannot be certain that we will be able to find a party willing to engage in a transaction on more attractive terms than the Merger. If the Merger Agreement is terminated under specified circumstances, we may be required to pay Parsley a termination fee or reimburse Parsley for certain of its expenses.

We will be subject to business uncertainties while the Merger is pending, which could adversely affect our businesses.

Uncertainty about the effect of the Merger on employees and customers may have an adverse effect on the Company. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter and could cause customers and others that deal with us to seek to change their existing business relationships with us. Employee retention at the Company may be particularly challenging during the pendency of the Merger, as employees may experience uncertainty about their roles with Parsley following the Merger. In addition, the Merger Agreement restricts us from entering into certain corporate transactions and taking other specified actions without the consent of Parsley, and generally requires us to continue our operations in the ordinary course, until completion of the Merger. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Merger.

The shares of Parsley Class A common stock to be received by our stockholders upon completion of the Merger will have different rights from shares of our common stock.

Upon completion of the Merger, our stockholders will no longer be stockholders of Jagged Peak. Instead, former Jagged Peak stockholders will become Parsley stockholders and while their rights as Parsley stockholders will continue to be governed by the laws of the state of Delaware, their rights will be subject to and governed by the terms of the Parsley certificate of incorporation, as amended, and the Parsley bylaws, as amended. The laws of the state of Delaware and terms of the Parsley amended and restated certificate of incorporation and the Parsley amended and restated bylaws are in some respects different than the terms of our certificate of incorporation and our bylaws, which currently govern the rights of our stockholders.

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Completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party.

The completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements, or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to us.

We will incur significant transaction and Merger-related costs in connection with the Merger, which may be in excess of those anticipated by us.

We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the Merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the Merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees. Many of these costs will be borne by us even if the Merger is not completed.

We may be a target of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the Merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, then that injunction may delay or prevent the Merger from being completed, which may adversely affect business, financial position and results of operation. Currently, we are unaware of any securities class action lawsuits or derivative lawsuits having been filed in connection with the Merger.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Recent sales of unregistered securities

None.

Purchases of equity securities by the issuer and affiliated purchasers

The following table summarizes the repurchase of our common stock during the three months ended September 30, 2019:

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
July 1, 2019 - July 31, 2019	1,786	$	8.75	—	—
August 1, 2019 - August 31, 2019	—	$	—	—	—
September 1, 2019 - September 30, 2019	1,418	$	7.48	—	—
Total	3,204	$	8.12	—	—

(1) Shares purchased represent shares of our common stock transferred to us to satisfy tax withholding obligations incurred upon the vesting of certain equity awards held by our employees.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number	Description of Exhibit
±2.1	Agreement and Plan of Merger, dated as of October 14, 2019, among Parsley, Merger Sub and Jagged Peak (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed with the SEC on October 15, 2019).
10.1	Voting and Support Agreement, dated October 14, 2019, by and among Parsley, Jagged Peak, Merger Sub and Quantum (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed with the SEC on October 15, 2019).
10.2	Voting and Support Agreement, dated October 14, 2019, by and among Parsley, Jagged Peak, Merger Sub and Bryan Sheffield (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed with the SEC on October 15, 2019).
*10.3	Waiver to Stockholders’ Agreement, dated July 23, 2019, by and among, Jagged Peak Energy Inc. and Q-Jagged Peak Energy Investment Partners, LLC.
*31.1	Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1	Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
**32.2	Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
*101.INS	Inline XBRL Instance Document - The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document.
*101.SCH	Inline XBRL Schema Document
*101.CAL	Inline XBRL Calculation Linkbase Document
*101.LAB	Inline XBRL Label Linkbase Document
*101.PRE	Inline XBRL Presentation Linkbase Document
*101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
*104	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
*	Filed herewith.
**	Furnished herewith.
±	Schedules have been omitted pursuant to Item 601(b)(2)(a)(5) of Regulation S-K. The registrant hereby undertakes to furnish supplementally copies of any of the omitted schedules upon request by the SEC.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		JAGGED PEAK ENERGY INC.
Date:	November 7, 2019	By:	/s/ JAMES J. KLECKNER
			Name:	James J. Kleckner
			Title:	Chief Executive Officer and President
Date:	November 7, 2019	By:	/s/ ROBERT W. HOWARD
			Name:	Robert W. Howard
			Title:	Executive Vice President, Chief Financial Officer
Date:	November 7, 2019	By:	/s/ SHONN D. STAHLECKER
			Name:	Shonn D. Stahlecker
			Title:	Controller

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EX-10.3

Exhibit 10.3

LIMITED CONSENT AND AGREEMENT

This Limited Consent and Agreement (this “Agreement”) dated as of [__], 2019 (the “Effective Date”), is among Jagged Peak Energy LLC, a Delaware limited liability company (the “Borrower”), Jagged Peak Energy Inc., a Delaware corporation (the “Guarantor”), Wells Fargo Bank, National Association, as administrative agent (in such capacity, the “Administrative Agent”) and as issuing lender (in such capacity, the “Issuing Lender”), and the Lenders (as defined below).

RECITALS

A.    Reference is made to that certain Amended and Restated Credit Agreement dated as of February 1, 2017 (as amended by that certain Amendment No. 1, Master Assignment and Agreement to Amended and Restated Credit Agreement dated as of October 26, 2017, that certain Amendment No. 2, Limited Waiver, Master Assignment and Agreement to Amended and Restated Credit Agreement dated as of March 21, 2018, that certain Amendment No. 3 to Amended and Restated Credit Agreement dated as of June 15, 2018, that certain Amendment No. 4, Master Assignment, and Agreement to Amended and Restated Credit Agreement dated as of August 9, 2018, that certain Amendment No. 5 to Amended and Restated Credit Agreement dated as of November 7, 2018, that certain Amendment No. 6 to Amended and Restated Credit Agreement dated as of April 29, 2019 and as further amended, restated, supplemented, or otherwise modified from time to time, the “Credit Agreement”) among the Borrower, the Guarantor, the Administrative Agent, the Issuing Lender and the financial institutions party thereto as lenders from time to time (the “Lenders”). Each term defined in the Credit Agreement and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary.

B.     Following the Effective Date, the Borrower will enter into (i) that certain Exchange Agreement with Callon Petroleum Operating Company in substantially the same form as the draft dated [__], 2019 and provided to the Administrative Agent and the Lenders on or before the date hereof (with such changes thereto as may be reasonably acceptable to the Administrative Agent, the “Callon Agreement”) pursuant to which the Borrower will exchange certain of its existing Oil and Gas Properties to which Proven Reserves that are categorized as “producing” are attributable, as such Oil and Gas Properties are more particularly described on Exhibit A-1 attached hereto, in exchange for certain Oil and Gas Properties described on Exhibit A-2 attached hereto (such transaction, the “Callon Exchange”) and (ii) that certain Exchange Agreement with Diamondback O&G LLC and Diamondback E&P LLC in substantially the same form as the draft dated [__], 2019 and provided to the Administrative Agent and the Lenders on or before the date hereof (with such changes thereto as may be reasonably acceptable to the Administrative Agent, the “Diamondback Agreement”) pursuant to which the Borrower will exchange certain of its existing Oil and Gas Properties to which Proven Reserves that are categorized as “producing” are attributable, as such Oil and Gas Properties are more particularly described on Exhibit B-1 attached hereto, in exchange for certain Oil and Gas Properties described on Exhibit B-2 attached hereto (such transaction, the “Diamondback Exchange”, and together with the Callon Exchange, collectively, the “Subject Exchanges”).

C.    Section 6.8(d) of the Credit Agreement provides that the Credit Parties may, subject to the terms and conditions thereof, enter into an Asset Sale of Oil and Gas Properties which are attributable to Proven Reserves, provided that if the consideration received is other Oil and Gas Properties in a like-kind exchange, the Oil and Gas Properties transferred by the Credit Parties in connection with such like-kind exchange shall not include any Proven Reserves categorized as “producing” under the definitions for oil and gas reserves promulgated by the Society of Petroleum Evaluation Engineers (or any generally recognized successor) as in effect at the time in question (the “Producing Requirement”).

D.     Notwithstanding the Producing Requirement, the Lenders have agreed, subject to the terms and conditions of this Agreement, to consent to each of the Subject Exchanges.

THEREFORE, the parties hereto hereby agree as follows:

Section 1.Defined Terms; Other Definitional Provisions. As used in this Agreement, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein. Article, Section, Schedule, and Exhibit references are to Articles and Sections of and Schedules and Exhibits to this Agreement, unless otherwise specified. The words “hereof”, “herein”, and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement. The term “including” means “including, without limitation,”. Paragraph headings have been inserted in this Agreement as a matter of convenience for reference only and it is agreed that such paragraph headings are not a part of this Agreement and shall not be used in the interpretation of any provision of this Agreement.

-1-

Section 2.    Limited Consent. Pursuant to the terms set forth herein and subject to the last sentence of this Section 2, the Lenders party hereto constituting Majority Lenders, hereby consent to the Callon Exchange, as such transaction is described in the Callon Agreement, and the Diamondback Exchange, as such transaction is described in the Diamondback Agreement. The limited consent described in this Section 2 is contingent upon the satisfaction of the conditions precedent set forth below in this Agreement and is limited to the Subject Exchanges only. Such consent is limited to the extent described herein and shall not be construed to be a consent to any other (existing or future) non-compliance with, or a temporary or permanent waiver of, Section 6.8(d) of the Credit Agreement, or any other terms, provisions, covenants, warranties or agreements contained in the Credit Agreement or in any of the other Credit Documents. The Administrative Agent and the Lenders reserve the right to exercise any rights and remedies available to them in connection with any other present or future Defaults or Events of Default with respect to the Credit Agreement or any other provision of any Credit Document. The Credit Parties acknowledge that any failure of the Administrative Agent or any Lender at any time or times hereafter to require strict performance by any Credit Party of any provision of the Credit Agreement and each other Credit Document shall not waive, affect or diminish any right of the Administrative Agent or any Lender to thereafter demand strict compliance therewith. Notwithstanding anything herein to the contrary, if (a) the Callon Exchange is not consummated pursuant to the terms of the Callon Agreement on or before the 90^th day following the Effective Date or (b) the Diamondback Exchange is not consummated pursuant to the terms of the Diamondback Agreement on or before the 90^th day following the Effective Date, the consent set forth herein solely as it relates to such Subject Exchange that is not consummated on or before the 90^th day following the Effective Date, shall expire and be of no further force and effect.

Section 3.    Representations and Warranties. Each Credit Party represents and warrants that, as of the date hereof: (a) the representations and warranties of such Credit Party contained in the Credit Agreement and in the other Credit Documents are true and correct in all material respects (except that such materiality qualifier shall not be applicable to any representations and warranties that already are qualified or modified by materiality in the text thereof) on and as of the Effective Date as if made on and as of such date, except that any representation and warranty which by its terms is made as of a specified date is true and correct in all material respects (except that such materiality qualifier shall not be applicable to any representations and warranties that already are qualified or modified by materiality in the text thereof) only as of such specified date; (b) no Default has occurred and is continuing; (c) the execution, delivery and performance of this Agreement are within such Credit Party’s powers and have been duly authorized by all necessary corporate, limited liability company, or partnership action; (d) this Agreement constitutes the legal, valid, and binding obligation of such Credit Party enforceable against such Credit Party in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity whether applied by a court of law or equity; (e) the execution, delivery and performance of this Agreement by such Credit Party do not require any authorization or approval or other action by, or any notice or filing with, any Governmental Authority other than those that have been obtained or provided and other than filings delivered hereunder to perfect Liens created under the Security Documents; and (f) the Liens under the Security Documents are valid and subsisting and secure the obligations under the Credit Documents.

Section 4.    Conditions to Effectiveness. This Agreement shall become effective on the Effective Date and enforceable against the parties hereto upon the occurrence of the following conditions precedent:

(a)    The Administrative Agent shall have received multiple original counterparts, as requested by the Administrative Agent, of this Agreement, duly and validly executed and delivered by duly authorized officers of the Borrower, the Guarantor, the Administrative Agent, and the Majority Lenders.

(b)    The Administrative Agent shall have received a copy, certified by a Responsible Officer of the Borrower as true, complete and correct, of the draft Callon Agreement, including all schedules and exhibits and any amendments or other modifications thereto in existence on the date hereof, all of which shall be in form and substance reasonably satisfactory to the Lenders.

(c)    The Administrative Agent shall have received a copy, certified by a Responsible Officer of the Borrower as true, complete and correct, of the draft Diamondback Agreement, including all schedules and exhibits and any amendments or other modifications thereto in existence on the date hereof, all of which shall be in form and substance reasonably satisfactory to the Lenders.

(d)    The Borrower shall have paid to the Administrative Agent all reasonable out-of-pocket costs and expenses that have been invoiced and are payable pursuant to Section 10.1 of the Credit Agreement.

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(e)    The Credit Parties shall have received any consents, licenses and approvals required in accordance with applicable law, or in accordance with any document, agreement, instrument or arrangement to which such Credit Party is a party, in connection with the execution, delivery, performance, validity and enforceability of this Agreement and the other Credit Documents.

(f)    No action, suit, investigation or other proceeding (including without limitation, the enactment or promulgation of a statute or rule) by or before any arbitrator or any Governmental Authority shall be threatened or pending and no preliminary or permanent injunction or order by a state or federal court shall have been entered (i) in connection with this Agreement, any other credit agreement, or any transaction contemplated hereby or thereby or (ii) which could reasonably be expected to result in a Material Adverse Change.

(g)    The Administrative Agent shall have received customary UCC search results and county-level real property record search results reflecting no prior Liens encumbering the Oil and Gas Properties described on Exhibit A-2 and Exhibit B-2 hereto for each jurisdiction requested by the Administrative Agent other than those being released on or prior to the Effective Date or Permitted Liens.

(h)    The Administrative Agent shall be reasonably satisfied with the environmental condition of the Oil and Gas Properties described on Exhibit A-2 and Exhibit B-2 hereto.

(i)    The Administrative Agent shall have received such other documents, governmental certificates, agreements, and lien searches as the Administrative Agent or any Lender may reasonably request.

Section 5.    Modifications to Subject Exchanges. No Credit Party will amend, supplement or otherwise modify the Callon Agreement, the Diamondback Agreement or any other documents or instruments evidencing, or agreements relating to or executed in connection with, any Subject Exchange, including any exhibits or schedules thereto, in any manner, unless such amendments, supplements or modifications are reasonably acceptable to the Administrative Agent in its sole discretion.

Section 6.    Acknowledgments and Agreements.

(a)    Each Credit Party acknowledges that on the date hereof all outstanding Secured Obligations are payable in accordance with their terms and each Credit Party waives any set-off, counterclaim, recoupment, defense, or other right, in each case, existing on the date hereof, with respect to such Secured Obligations. Each party hereto does hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect, and each Credit Party acknowledges and agrees that its respective liabilities and obligations under the Credit Agreement, as amended herby, and the other Credit Documents are not impaired in any respect by this Agreement.

(b)    The Administrative Agent, the Issuing Lender, and the Lenders hereby expressly reserve all of their rights, remedies, and claims under the Credit Documents. Nothing in this Agreement shall constitute a waiver or relinquishment of (i) any Default or Event of Default under any of the Credit Documents, (ii) any of the agreements, terms or conditions contained in any of the Credit Documents (other than those specifically described in Section 2 hereof), (iii) any rights or remedies of the Administrative Agent, the Issuing Lender, or any Lender with respect to the Credit Documents, or (iv) the rights of the Administrative Agent, the Issuing Lender, or any Lender to collect the full amounts owing to them under the Credit Documents.

(c)    This Agreement is a Credit Document for the purposes of the provisions of the other Credit Documents. Without limiting the foregoing, any breach of representations, warranties, and covenants under this Agreement shall be a Default or Event of Default, as applicable, under the Credit Agreement.

Section 7.    Reaffirmation of the Guaranty. The Guarantor hereby ratifies, confirms, acknowledges and agrees that its obligations under the Guaranty are in full force and effect and that the Guarantor continues to unconditionally and irrevocably guarantee the full and punctual payment, when due, whether at stated maturity or earlier by acceleration or otherwise, of all the Guaranteed Obligations (as defined in the Guaranty), and its execution and delivery of this Agreement does not indicate or establish an approval or consent requirement by the Guarantor under the Guaranty, in connection with the execution and delivery of amendments, consents or waivers to the Credit Agreement or any of the other Credit Documents.

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Section 8.    Reaffirmation of Liens. Each Credit Party (a) reaffirms the terms of and its obligations (and the security interests granted by it) under each Security Document to which it is a party, and agrees that each such Security Document will continue in full force and effect to secure the Secured Obligations as the same may be amended, supplemented, or otherwise modified from time to time, and (b) acknowledges, represents, warrants and agrees that the Liens and security interests granted by it pursuant to the Security Documents are valid, enforceable and subsisting and create an Acceptable Security Interest to secure the Secured Obligations.

Section 9.    Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page of this Agreement by facsimile or in electronic (i.e., “pdf” or “tif”) format shall be effective as delivery of a manually executed counterpart of this Agreement.

Section 10.    Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement.

Section 11.    Severability. In case one or more of the provisions of this Agreement shall for any reason be invalid, illegal or unenforceable in any respect under any applicable law, the validity, legality and enforceability of the remaining provisions contained herein or in the other Credit Documents shall not be affected or impaired thereby.

Section 12.    Governing Law. This Agreement shall be deemed to be a contract made under and shall be governed by and construed in accordance with the laws of the State of New York without regard to conflicts of laws principles (other than Sections 5-1401 and 5-1402 of the General Obligations Law of the State of New York).

Section 13.    Entire Agreement.THIS AGREEMENT, THE CREDIT AGREEMENT, THE NOTES, AND THE OTHER CREDIT DOCUMENTS CONSTITUTE THE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[The remainder of this page has been left blank intentionally.]

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EXECUTED to be effective as of the date first above written.

BORROWER:
	JAGGED PEAK ENERGY LLC
	By:	/s/ CHRISTOPHER HUMBER
	Name:	Christopher Humber
	Title:	Executive Vice President, General Counsel and Secretary
GUARANTOR:
	JAGGED PEAK ENERGY INC.
	By:	/s/ CHRISTOPHER HUMBER
	Name:	Christopher Humber
	Title:	Executive Vice President, General Counsel and Secretary

Signature Page to Limited Consent and Agreement

ADMINSTRATIVE AGENT/ISSUING
LENDER/LENDER:
WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, Issuing Lender, and a Lender
By:	/s/ ZACHARY KRAMER
Name:	Zachary Kramer
Title:	Vice President

Signature Page Limited Consent and Agreement

LENDERS:
FIFTH THIRD BANK, as a Lender
By:	/s/ JONATHAN H. LEE
Name:	Jonathan H. Lee
Title:	Director

Signature Page Limited Consent and Agreement

ABN AMRO CAPTIAL USA LLC, as a Lender
By:	/s/ DARRELL HOLLEY
Name:	Darrell Holley
Title:	Managing Director
By:	/s/ MICHAELA BRAUN
Name:	Michaela Braun
Title:	Director

Signature Page Limited Consent and Agreement

KEYBANK NATIONAL ASSOCIATION, as a Lender
By:	/s/ GEORGE E. MCKEAN
Name:	George E. McKean
Title:	Senior Vice President

Signature Page Limited Consent and Agreement

FIRST TENNESSEE BANK NATIONAL ASSOCIATION, as a Lender
By:	/s/ W. DAVID MCCARVER IV
Name:	W. David McCarver IV
Title:	Senior Vice President

Signature Page Limited Consent and Agreement

CITIBANK, N.A., as a Lender
By:	/s/ CLIFF VAZ
Name:	Cliff Vaz
Title:	Vice President

Signature Page to Limited Consent and Agreement

JPMORGAN CHASE BANK, N.A., as a Lender
By:	/s/ DARREN VANEK
Name:	Darren Vanek
Title:	Authorized Officer

Signature Page to Limited Consent and Agreement

GOLDMAN SACHS BANK USA, as a Lender
By:	/s/ JAMIE MINIERI
Name:	Jamie Minieri
Title:	Authorized Signatory

Signature Page to Limited Consent and Agreement

UBS AG, STAMFORD BRANCH, as a Lender
By:	/s/ KENNETH CHIN
Name:	Kenneth Chin
Title:	Director
By:	/s/ DARLENE ARIAS
Name:	Darlene Arias
Title:	Director

Signature Page to Limited Consent and Agreement

BMO HARRIS BANK N.A., as a Lender
By:	/s/ MELISSA GUZMANN
Name:	Melissa Guzmann
Title:	Director

Signature Page to Limited Consent and Agreement

ROYAL BANK OF CANADA, as a Lender
By:	/s/ KRISTAN SPIVEY
Name:	Kristen Spivey
Title:	Authorized Signatory

Signature Page to Limited Consent and Agreement

COMERICA BANK, as a Lender
By:	/s/ COURTNEY A. REHM
Name:	Courtney A. Rehm
Title:	Portfolio Manager

Signature Page to Limited Consent and Agreement

U.S. BANK NATIONAL ASSOCIATION, as a Lender
By:	/s/ JOHN C. LOZANO
Name:	John C. Lozano
Title:	Senior Vice President

Signature Page to Limited Consent and Agreement

BOKF, NA, as a Lender
By:	/s/ ERIN M. DUNN
Name:	Erin M. Dunn
Title:	Vice President

Signature Page to Limited Consent and Agreement

EX-31.1

Exhibit 31.1

CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER

I, James J. Kleckner, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Jagged Peak Energy Inc.;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected or is reasonably likely to materially affect the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2019	/s/ JAMES J. KLECKNER
		Name:	James J. Kleckner
		Title:	Chief Executive Officer and President

EX-31.2

Exhibit 31.2

CERTIFICATION OF THE PRINCIPAL FINANCIAL OFFICER

I, Robert W. Howard, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Jagged Peak Energy Inc.;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected or is reasonably likely to materially affect the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2019	/s/ ROBERT W. HOWARD
		Name:	Robert W. Howard
		Title:	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification

In connection with the Quarterly Report of Jagged Peak Energy Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), James J. Kleckner, Chief Executive Officer and President, does hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 7, 2019	/s/ JAMES J. KLECKNER
		Name:	James J. Kleckner
		Title:	Chief Executive Officer and President

EX-32.2

Exhibit 32.2

Certification

In connection with the Quarterly Report of Jagged Peak Energy Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Robert W. Howard, Executive Vice President and Chief Financial Officer, does hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 7, 2019	/s/ ROBERT W. HOWARD
		Name:	Robert W. Howard
		Title:	Executive Vice President and Chief Financial Officer

XML

Leases - Lease Cost (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Leases [Abstract]
Operating lease cost	$ 9,297	$ 27,891
Short-term lease cost	5,273	33,553
Variable lease cost	369	941
Total lease cost	$ 14,939	$ 62,385

XML

Fair Value Measurements - Assets and liabilities measured on a recurring basis (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative contracts	$ 61,967	$ 134,991
Liabilities due to commodity derivative contracts	32,397	34,370
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative contracts	61,967	134,991
Liabilities due to commodity derivative contracts	$ 32,397	$ 34,370

XML

Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Related Party Transaction [Line Items]
Outstanding payables	$ 0		$ 0		$ 2,600
Phoenix Lease Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	17	$ 98	68	$ 319
Oil Gathering Agreement | Oryx Midstream Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	0	6,435	14,041	16,719
Leasing Of Equipment | Oryx Midstream Services, LLC
Related Party Transaction [Line Items]
Fees paid to related party	$ 32	$ 140	548	$ 440
Pipeline easements and Right of Way agreements | Oryx Midstream Services, LLC
Related Party Transaction [Line Items]
Amounts received from related party			$ 45

XML

Leases

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Leases

Leases

The Company’s ROU assets include leases for its drilling rigs, its corporate headquarters and certain office equipment, with the significant lease types described below in more detail. As of September 30, 2019, the Company’s leases have remaining lease terms of 0.5 years to 8.7 years. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company’s lease agreements do not contain any material restrictive covenants. Additionally, the Company currently does not have any finance leases.

Short-term leases have a term of 12 months or less. The Company recognizes short-term lease cost based on usage of the asset over the lease term. There are no ROU assets or lease liabilities recorded for such leases.

Drilling Rigs. The Company enters into short- and long-term contracts for drilling rigs with third parties to support its development plan. The short-term drilling rig arrangements can range from a term that is in effect until drilling operations are completed on a contractually specified well or well pad, or for a given number of months not to exceed 12 months. The Company’s long-term drilling contracts are generally structured with an initial noncancelable term of one to two years. Upon mutual agreement with the contractor, the Company typically has the option to extend the initial contract for additional wells, well pads or a contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.

The Company has determined that it cannot conclude with reasonable certainty that it will extend the drilling contracts past their respective primary term, and as a result, the Company uses the primary term in its calculation of the ROU asset and lease liability. The Company capitalizes the costs of its short- and long-term drilling rigs to oil and natural gas properties.

Corporate Headquarters. The Company leases office space for its corporate headquarters. The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the noncancelable term. As such, the Company uses the noncancelable term in its calculation of the ROU asset and lease liability. The lease for the Company’s corporate headquarters provides for increases in future minimum annual rental payments as defined in the lease agreement. The lease also includes real estate taxes and common area maintenance charges, which are expensed when occurred. The Company classifies its leases for office space as operating leases, with the costs recognized as “general and administrative expenses” in its consolidated statements of operations.

Lease Costs

Lease cost for operating leases is recognized on a straight-line basis over the lease term. Short-term lease costs exclude expenses related to leases with a lease term of one month or less. Lease costs are presented gross and a portion of these costs will be reimbursed by the Company’s other working interest partners for their proportionate share. The total gross lease cost for the periods indicated are as follows:

	Three months ended		Nine months ended
(in thousands)	September 30, 2019		September 30, 2019
Operating lease cost (1)	$	9,297	$	27,891
Short-term lease cost (2)	5,273		33,553
Variable lease cost (3)	369		941
Total lease cost	$	14,939	$	62,385

(1) The total operating lease cost may not agree to the cash paid for operating lease liabilities on the consolidated statements of cash flows due to the timing of cash payments and incurred costs.

(2) Short-term lease cost during the three months ended September 30, 2019 is primarily related to one short-term drilling rig and certain field equipment. During the three months ended March 31, 2019, costs from the Company’s frac fleets were also included in this amount, which is seen in the nine months ended September 30, 2019. Subsequent to March 31, 2019, the Company determined that the frac fleets are considered to have a term of one month or less and are no longer included in the short-term lease cost disclosure.

(3) Variable lease costs were not included in the measurement of the Company’s lease balances and primarily relate to common area maintenance charges on the Company’s corporate headquarters.

In accordance with the Company’s accounting policies, the Company’s share of these lease costs was either capitalized to oil and natural gas properties, or recorded within either general and administrative or lease operating expenses.

Lease Maturities

The table below reconciles the undiscounted lease payment maturities to the lease liabilities for the Company’s operating leases as of September 30, 2019:

	Remainder		Payments Due by Period for the Year Ending December 31,
(in thousands)	of 2019		2020		2021		2022		2023		Thereafter		Total
Operating lease payments (1)	$	9,450	$	33,428	$	1,547	$	1,558	$	1,589	$	7,378	$	54,950
Less: amount of lease payments representing interest													(3,168		)
Present value of future minimum lease payments													51,782
Less: current operating lease liabilities													(36,263		)
Long-term operating lease liabilities													$	15,519

(1) The operating lease payments represent the total payment obligation to be incurred over the remaining life of the lease. A portion of these costs will be billed to the Company’s working interest partners when the payment is incurred based on the nature of the cost and the relative working interest of the working interest partner.

Supplemental Lease Information

Supplemental information related to the Company’s operating leases was as follows:

	September 30, 2019
Weighted average remaining lease term - operating leases (in years)	2.8
Weighted average discount rate - operating leases (1)	4.2	%

(1) Upon adoption of the new lease standard, discount rates used for existing leases were established at January 1, 2019.

As of September 30, 2019, the Company has an additional lease that has not yet commenced related to additional office space for our corporate headquarters. The new lease is expected to commence in the first quarter of 2020, has a remaining lease term of 3.7 years and expected cash payments of $1.5 million.

As described in Note 2, Significant Accounting Policies and Related Matters, the Company adopted ASU 2016-02 using the modified retrospective approach as permitted under ASU 2018-11. This ASU also requires entities electing this transition method to provide the required disclosures under ASC 840 for all periods that continue to be presented in accordance with ASC 840. As such, the Company included the future minimum payments for noncancelable operating leases as of December 31, 2018, in accordance with ASC 840, as follows:

(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

In addition, lease payments associated with these operating leases were $0.5 million and $1.8 million for the three and nine months ended September 30, 2018, respectively.

XML

Earnings Per Share

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per share 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. Shares to be issued in exchange for incentive units are already outstanding and will not have a dilutive effect upon vesting. 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 antidilutive.

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share amounts)	2019		2018			2019			2018
Net income (loss) attributable to common stock	$	30,558	$	(26,566	)	$	(22,423	)	$	(20,888	)
Basic weighted average shares outstanding	213,403		213,180			213,349			213,109
Dilutive unvested RSUs	35		—			—			—
Dilutive unvested PSUs	262		—			—			—
Diluted weighted average shares outstanding	213,700		213,180			213,349			213,109
Net income (loss) per common share:
Basic	$	0.14	$	(0.12	)	$	(0.11	)	$	(0.10	)
Diluted	$	0.14	$	(0.12	)	$	(0.11	)	$	(0.10	)

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. These shares could dilute basic earnings per share in future periods.

	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands)	2019	2018	2019	2018
Number of antidilutive units: (1)
Antidilutive unvested RSUs	1,575	791	1,455	721
Antidilutive unvested PSUs	225	603	1,076	496

(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.

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Derivative Instruments - Balance Sheet Location (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Derivative Asset [Abstract]
Gross amounts presented on the balance sheet, assets	$ 61,967	$ 134,991
Netting adjustments not offset on the balance sheet, assets	(30,298)	(28,483)
Assets from commodity derivative contracts, assets	31,669	106,508
Derivative Liability [Abstract]
Gross amounts presented on the balance sheet, liabilities	32,397	34,370
Netting adjustments not offset on the balance sheet, liabilities	(30,298)	(28,483)
Liabilities from commodity derivative contracts, liabilities	2,099	5,887
Commodity contracts | Current assets - derivative instruments
Derivative Asset [Abstract]
Gross amounts presented on the balance sheet, assets	48,006	103,092
Netting adjustments not offset on the balance sheet, assets	(25,639)	(18,815)
Assets from commodity derivative contracts, assets	22,367	84,277
Commodity contracts | Noncurrent assets - derivative instruments
Derivative Asset [Abstract]
Gross amounts presented on the balance sheet, assets	13,961	31,899
Netting adjustments not offset on the balance sheet, assets	(4,659)	(9,668)
Assets from commodity derivative contracts, assets	9,302	22,231
Commodity contracts | Current liabilities - derivative instruments
Derivative Liability [Abstract]
Gross amounts presented on the balance sheet, liabilities	27,738	23,208
Netting adjustments not offset on the balance sheet, liabilities	(25,639)	(18,815)
Liabilities from commodity derivative contracts, liabilities	2,099	4,393
Commodity contracts | Noncurrent liabilities - derivative instruments
Derivative Liability [Abstract]
Gross amounts presented on the balance sheet, liabilities	4,659	11,162
Netting adjustments not offset on the balance sheet, liabilities	(4,659)	(9,668)
Liabilities from commodity derivative contracts, liabilities	$ 0	$ 1,494

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Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Lease cost

The total gross lease cost for the periods indicated are as follows:

	Three months ended		Nine months ended
(in thousands)	September 30, 2019		September 30, 2019
Operating lease cost (1)	$	9,297	$	27,891
Short-term lease cost (2)	5,273		33,553
Variable lease cost (3)	369		941
Total lease cost	$	14,939	$	62,385

(1) The total operating lease cost may not agree to the cash paid for operating lease liabilities on the consolidated statements of cash flows due to the timing of cash payments and incurred costs.

(2) Short-term lease cost during the three months ended September 30, 2019 is primarily related to one short-term drilling rig and certain field equipment. During the three months ended March 31, 2019, costs from the Company’s frac fleets were also included in this amount, which is seen in the nine months ended September 30, 2019. Subsequent to March 31, 2019, the Company determined that the frac fleets are considered to have a term of one month or less and are no longer included in the short-term lease cost disclosure.

(3)

Variable lease costs were not included in the measurement of the Company’s lease balances and primarily relate to common area maintenance charges on the Company’s corporate headquarters.

Operating lease liability maturity

The table below reconciles the undiscounted lease payment maturities to the lease liabilities for the Company’s operating leases as of September 30, 2019:

	Remainder		Payments Due by Period for the Year Ending December 31,
(in thousands)	of 2019		2020		2021		2022		2023		Thereafter		Total
Operating lease payments (1)	$	9,450	$	33,428	$	1,547	$	1,558	$	1,589	$	7,378	$	54,950
Less: amount of lease payments representing interest													(3,168		)
Present value of future minimum lease payments													51,782
Less: current operating lease liabilities													(36,263		)
Long-term operating lease liabilities													$	15,519

(1) The operating lease payments represent the total payment obligation to be incurred over the remaining life of the lease. A portion of these costs will be billed to the Company’s working interest partners when the payment is incurred based on the nature of the cost and the relative working interest of the working interest partner.

Schedule Of Weighted Average Remaining Lease Term and Weighted Average Discount Rate For Operating Leases Table

Supplemental information related to the Company’s operating leases was as follows:

	September 30, 2019
Weighted average remaining lease term - operating leases (in years)	2.8
Weighted average discount rate - operating leases (1)	4.2	%

(1)

Upon adoption of the new lease standard, discount rates used for existing leases were established at January 1, 2019.

Schedule of minimum lease payments on operating loans with previous guidance

the Company included the future minimum payments for noncancelable operating leases as of December 31, 2018, in accordance with ASC 840, as follows:

(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

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Significant Accounting Policies and Related Matters - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Accrued capital expenditures	$ 80,153	$ 74,688
Accrual for Taxes Other than Income Taxes, Current	12,765	7,802
Interest Payable, Current	12,645	4,896
Accrued accounts payable	1,454	5,941
Royalties payable	9,684	19,964
Accrued LOE	9,944	8,014
Other current liabilities	10,210	8,707
Total accrued liabilities	$ 136,855	$ 130,012

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2019	Dec. 31, 2018
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)	213,404,153	213,187,780

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (22,423)	$ (20,888)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion expense	186,365	160,552
Impairment of unproved oil and natural gas properties	32,763	53
Amortization of debt issuance costs	1,770	1,753
Deferred income taxes	(5,986)	14,737
Equity-based compensation	11,025	80,671
(Gain) loss on commodity derivatives	85,702	110,426
Net cash receipts (payments) on settled derivatives	(14,651)	(33,705)
(Gain) on sale of oil and natural gas properties	0	6,225
Other	(98)	(234)
Change in operating assets and liabilities:
Accounts receivable and other current assets	(2,407)	(29,854)
Accounts payable and accrued liabilities	641	40,461
Net cash provided by operating activities	272,701	317,747
CASH FLOWS FROM INVESTING ACTIVITIES
Leasehold and acquisition costs	(32,931)	(18,854)
Development of oil and natural gas properties	(477,681)	(551,059)
Other capital expenditures	(837)	(3,245)
Proceeds from sale of oil and natural gas properties	0	8,377
Net cash used in investing activities	(511,449)	(564,781)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from credit facility	215,000	165,000
Repayment of credit facility	0	(320,000)
Proceeds from senior notes	0	500,000
Debt issuance costs	(197)	(13,350)
Employee tax withholding for settlement of equity compensation awards	(681)	(200)
Net cash provided by financing activities	214,122	331,450
NET CHANGE IN CASH AND CASH EQUIVALENTS	(24,626)	84,416
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	35,229	9,523
CASH AND CASH EQUIVALENTS, END OF PERIOD	10,603	93,939
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest	18,200	4,009
Cash paid for income taxes	0	0
Cash paid for operating lease liabilities included in cash flows from operating activities	1,123
Cash paid for operating lease liabilities included in cash flows from investing activities	26,918
SUPPLEMENTAL DISCLOSURE OF NONCASH OPERATING ACTIVITIES
Lease liabilities arising from obtaining right-of-use assets	73,413
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	102,275	100,780
Asset retirement obligations	$ 1,619	$ 567

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Equity-based Compensation (Tables)

9 Months Ended

Sep. 30, 2019

Share-based Payment Arrangement [Abstract]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan

Equity-based compensation expense, for each type of equity-based award, was as follows for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Incentive unit awards	$	856	$	609	$	2,050	$	75,767
Restricted stock unit awards	1,624		883		4,520		2,996
Performance stock unit awards	1,403		1,016		3,987		1,513
Restricted stock unit awards issued to nonemployee directors	215		106		468		395
Equity-based compensation expense	$	4,098	$	2,614	$	11,025	$	80,671

Schedule of Share-based Compensation, Incentive Units, Activity

The following table summarizes the Company’s award activity for incentive units, restricted stock units (“RSU”) and PSUs for the nine months ended September 30, 2019:

	Incentive Units (2)		RSUs		PSUs
Unvested at December 31, 2018	5,397,555		871,119		691,363
Awards Granted (1)	28,991		1,232,503		657,664
Vested	(2,598,796	)	(291,704	)	—
Forfeited	(28,991	)	(137,510	)	(135,299	)
Unvested at September 30, 2019	2,798,759		1,674,408		1,213,728

(1) The weighted average grant-date fair value was $8.27 for incentive units, $10.18 for RSUs and $12.63 for PSUs. The weighted average grant-date fair value for PSUs was calculated using a Monte Carlo simulation.

(2) Included in the unvested incentive units at September 30, 2019 are 2,433,821 units for which equity-based compensation expense has been accelerated and fully recognized.

The following table reflects the future equity-based compensation expense to be recorded for each type of award that was outstanding at September 30, 2019:

	Incentive Units		RSUs (1)		PSUs
Compensation costs remaining at September 30, 2019 (in millions)	$	3.5	$	13.8	$	9.5
Weighted average remaining period at September 30, 2019 (in years)	1.6		2.1		1.8

(1)

The remaining compensation cost at September 30, 2019 for the nonemployee director RSUs was $0.5 million, with a weighted average remaining period of 0.6 years.

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Significant Accounting Policies and Related Matters (Policies)

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying unaudited interim consolidated 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”) for interim financial information, and should be read in conjunction with the financial statements, summary of significant accounting policies and footnotes included in the 2018 Form 10-K. Accordingly, certain disclosures required by GAAP and normally included in Annual Reports on Form 10-K have been condensed or omitted from this report; however, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in the 2018 Form 10-K. All significant intercompany balances and transactions have been eliminated.

It is the opinion of management that all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identical to its comprehensive income or loss. Operating results for the periods presented are not necessarily indicative of expected results for the full year because of the impact of fluctuations in prices received for oil, natural gas and NGLs, expected production changes due to development activities, natural production declines, the uncertainty of exploration and development drilling results, the fair value of derivative instruments and other factors.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current presentation.

Use of Estimates

Use of Estimates

In the course of preparing the consolidated 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 financial statements include, among other things, (1) oil and natural gas reserve quantities, which impact depletion of oil and natural gas properties and evaluation and measurement of any impairment of proved oil and natural gas properties, (2) impairment of unproved oil and natural gas properties, which includes assumptions about future development and lease renewal, commodity price outlooks and prevailing market rates, (3) accrued operating and capital costs, (4) asset retirement obligation timing and costs, (5) lease terms and incremental borrowing rates used in the determination of lease assets and liabilities, (6) measurement of equity-based compensation, (7) fair value of derivative instruments, (8) deferred income taxes and (9) disclosure of commitments and contingencies. Changes in these estimates and assumptions could have a significant impact on results in future periods.

Revenue Recognition

Revenue Recognition

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 from the Delaware Basin. The Company believes the disaggregation of revenues into oil sales, natural gas sales and NGL sales, as seen on the consolidated statements of operations, is an appropriate level of detail for its primary activity.

Contract Assets and Liabilities. The Company’s performance obligations for its contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company did not have any contract assets or liabilities as of September 30, 2019 and December 31, 2018.

Performance Obligations. 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. 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.

Oil and Natural Gas Properties

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.

Leases

Leases

Following the adoption of Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) on January 1, 2019, the Company determines if an arrangement is a lease at inception of the contract. Operating lease right-of-use (“ROU”) assets and operating lease liabilities are recognized based on the present value of the future lease payments over the lease term at commencement date. For leases that do not provide implicit rates, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Operating lease ROU assets exclude lease incentives and initial direct costs incurred. Operating lease cost is recognized on a straight-line basis over the lease term. The Company currently does not have any finance leases.

The Company has lease agreements with lease and non-lease components, which are all accounted for as a single lease component.

Short-term leases have a term of 12 months or less. The Company recognizes short-term lease cost based on usage of the asset over the lease term and does not record a ROU asset or lease liability for such leases.

The Company monitors for events or changes in circumstances that may require a reassessment or impairment of its leases, at which time the Company's ROU assets for operating leases may be reduced by impairment losses. 

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Recently Adopted Accounting Standards

Leases. In February 2016, the Financial Accounting Standards Board (“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. ASU 2016-02 retains a distinction between operating and finance leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. Entities are required to recognize operating or finance leases as ROU assets and lease liabilities on the balance sheet as well as disclose key information about leasing arrangements in the notes to the financial statements. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. This ASU does not apply to leases of mineral rights to explore for or use oil and natural gas.

The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective approach as permitted under ASU 2018-11, which allows the Company to apply the legacy lease guidance and disclosure requirements (“ASC 840”) in the comparative periods presented for the year of adoption. The adoption did not require an adjustment to opening retained earnings for a cumulative effect adjustment.

As part of the adoption, the Company elected the short-term lease recognition policy election for all leases that qualify, and as such, no ROU assets or lease liabilities will be recorded on the balance sheet when the term of the lease is less than 12 months. The Company also elected the following practical expedients:

•the package of transition practical expedients, permitting the Company to not reassess its prior conclusions about lease identification, lease classification and initial direct costs;

•the practical expedient pertaining to land easements, which allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way; and

•the practical expedient to not separate lease and non-lease components.

The new lease standard impacted the Company’s consolidated balance sheets as a result of the ROU assets and operating lease liabilities but did not impact its consolidated statements of operations or consolidated statements of cash flows. The Company currently has no finance leases. The impact to the opening January 1, 2019 consolidated balance sheets was as follows:

(in thousands)	Opening Balances as of January 1, 2019		Adoption of ASC 842			As Adjusted at January 1, 2019
Operating lease right-of-use assets (1)	$	—	$	73,413		$	73,413
Current operating lease liabilities (1)	$	—	$	35,043		$	35,043
Long-term operating lease liabilities (1)	—		42,814			42,814
Other long-term liabilities (2)	4,444		(4,444		)	—

(1) Represents the recognition of operating lease ROU assets and the associated lease liabilities.

(2) Represents the derecognition of deferred rent and leasehold incentives that were accounted for under ASC 840.

Adoption of the new standard did not impact the Company’s previously reported consolidated balance sheets, results of operations, cash flows statements or statements of changes in equity.

For more information on the Company’s leases, refer to Note 10, Leases.

Accounting Standards Not Yet Adopted

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 current 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 will be applied using a modified retrospective approach which may result 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 not been significant, and the Company does not believe the adoption of ASU 2016-13 will have a material impact on its consolidated financial statements.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value, Assets and Liabilities Measured on 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)	September 30, 2019		December 31, 2018
Assets from commodity derivative contracts	$	61,967	$	134,991
Liabilities due to commodity derivative contracts	$	32,397	$	34,370

Fair Value, Estimate Not Practicable

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:

	September 30, 2019				December 31, 2018
(in thousands)	Principal Amount		Fair Value		Principal Amount		Fair Value
Long-term debt:
Senior secured revolving credit facility	$	215,000	$	215,000	$	—	$	—
5.875% senior unsecured notes due 2026	$	500,000	$	501,490	$	500,000	$	466,250

Fair Value, Noncash Impairments

The following table sets forth the noncash impairments of both proved and unproved properties for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Proved oil and natural gas property impairments	$	—	$	—	$	—	$	—
Unproved oil and natural gas property impairments (1)	31,817		—		32,763		53
	$	31,817	$	—	$	32,763	$	53

(1) Impairment of unproved oil and natural gas properties in 2019 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 2018 resulted from expirations of certain undeveloped leases.

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Income Taxes - Narrative (Details)	9 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Federal statutory rate	21.00%

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Debt - Schedule of Debt (Details) - USD ($)	Sep. 30, 2019	Dec. 31, 2018
Long-term debt:
Long-term debt	$ 705,269,000	$ 489,239,000
Debt issuance costs on senior unsecured notes	(9,731,000)	(10,761,000)
Senior Notes | 5.875% senior unsecured notes due 2026
Long-term debt:
Long-term debt	$ 500,000,000	500,000,000
Interest rate	5.875%
Revolving Credit Facility | Senior secured revolving credit facility
Long-term debt:
Long-term debt	$ 215,000,000	$ 0

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Equity-based Compensation - Additional Information (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Management Holdco | Incentive unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation modification	$ 71.3

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 10,603	$ 35,229
Accounts receivable	62,062	61,186
Derivative instruments	48,006	103,092
Prepaid and other current assets	3,158	1,627
Total current assets	123,829	201,134
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method	2,377,765	1,905,498
Accumulated depletion	(569,733)	(386,883)
Total oil and gas properties, net	1,808,032	1,518,615
Other property and equipment, net	10,155	11,670
Total property and equipment, net	1,818,187	1,530,285
OTHER NONCURRENT ASSETS
Operating lease right-of-use assets	47,489
Derivative instruments	13,961	31,899
Other assets	3,279	3,823
Total noncurrent assets	64,729	35,722
TOTAL ASSETS	2,006,745	1,767,141
CURRENT LIABILITIES
Accounts payable	23,531	34,762
Accrued liabilities	136,855	130,012
Operating lease liabilities	36,263
Derivative instruments	27,738	23,208
Total current liabilities	224,387	187,982
LONG-TERM LIABILITIES
Long-term debt	705,269	489,239
Derivative instruments	4,659	11,162
Asset retirement obligations	2,609	1,946
Deferred income taxes	118,432	124,418
Operating lease liabilities	15,519
Other long-term liabilities	0	4,444
Total long-term liabilities	846,488	631,209
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, 213,404,153 shares issued at September 30, 2019; 213,187,780 shares issued at December 31, 2018	2,134	2,132
Additional paid-in capital	867,159	856,818
Retained earnings	66,577	89,000
Total stockholders’ equity	935,870	947,950
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 2,006,745	$ 1,767,141

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)
Beginning Balance at Dec. 31, 2017	$ 699,345	$ 2,129	$ 773,674	$ (76,458)
Beginning Balance (in shares) at Dec. 31, 2017		212,931
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	(200)	$ 2	(202)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)		180
Equity-based compensation	75,678		75,678
Net income (loss)	(39,403)			(39,403)
Ending Balance at Mar. 31, 2018	735,420	$ 2,131	849,150	(115,861)
Ending Balance (in shares) at Mar. 31, 2018		213,111
Beginning Balance at Dec. 31, 2017	699,345	$ 2,129	773,674	(76,458)
Beginning Balance (in shares) at Dec. 31, 2017		212,931
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(20,888)
Ending Balance at Sep. 30, 2018	758,929	$ 2,132	854,143	(97,346)
Ending Balance (in shares) at Sep. 30, 2018		213,181
Beginning Balance at Mar. 31, 2018	735,420	$ 2,131	849,150	(115,861)
Beginning Balance (in shares) at Mar. 31, 2018		213,111
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	1	$ 1
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)		68
Equity-based compensation	2,379		2,379
Net income (loss)	45,081			45,081
Ending Balance at Jun. 30, 2018	782,881	$ 2,132	851,529	(70,780)
Ending Balance (in shares) at Jun. 30, 2018		213,179
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	0	$ 0
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)		2
Equity-based compensation	2,614		2,614
Net income (loss)	(26,566)			(26,566)
Ending Balance at Sep. 30, 2018	758,929	$ 2,132	854,143	(97,346)
Ending Balance (in shares) at Sep. 30, 2018		213,181
Beginning Balance at Dec. 31, 2018	947,950	$ 2,132	856,818	89,000
Beginning Balance (in shares) at Dec. 31, 2018		213,188
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	(279)	$ 2	(281)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)		167
Equity-based compensation	2,934		2,934
Net income (loss)	(94,888)			(94,888)
Ending Balance at Mar. 31, 2019	855,717	$ 2,134	859,471	(5,888)
Ending Balance (in shares) at Mar. 31, 2019		213,355
Beginning Balance at Dec. 31, 2018	947,950	$ 2,132	856,818	89,000
Beginning Balance (in shares) at Dec. 31, 2018		213,188
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(22,423)
Ending Balance at Sep. 30, 2019	935,870	$ 2,134	867,159	66,577
Ending Balance (in shares) at Sep. 30, 2019		213,404
Beginning Balance at Mar. 31, 2019	855,717	$ 2,134	859,471	(5,888)
Beginning Balance (in shares) at Mar. 31, 2019		213,355
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	(376)		(376)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)		39
Equity-based compensation	3,993		3,993
Net income (loss)	41,907			41,907
Ending Balance at Jun. 30, 2019	901,241	$ 2,134	863,088	36,019
Ending Balance (in shares) at Jun. 30, 2019		213,394
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	(27)		(27)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)		10
Equity-based compensation	4,098		4,098
Net income (loss)	30,558			30,558
Ending Balance at Sep. 30, 2019	$ 935,870	$ 2,134	$ 867,159	$ 66,577
Ending Balance (in shares) at Sep. 30, 2019		213,404

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The following table summarizes the changes in the carrying amount of the asset retirement obligations for the nine months ended September 30, 2019. The current portion of the asset retirement obligation liability is included in accrued liabilities on the consolidated balance sheets.

(in thousands)
Asset retirement obligations at January 1, 2019	$	2,072
Liabilities incurred and assumed	902
Liability settlements	(318		)
Revisions of estimated liabilities	717
Accretion	159
Asset retirement obligations at September 30, 2019	3,532
Less current portion of asset retirement obligations	(923		)
Long-term asset retirement obligations	$	2,609

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Debt (Tables)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Schedule of Debt

The Company’s debt consisted of the following at September 30, 2019 and December 31, 2018:

(in thousands)	September 30, 2019			December 31, 2018
Senior secured revolving credit facility	$	215,000		$	—
5.875% senior unsecured notes due 2026	500,000			500,000
Debt issuance costs on senior unsecured notes	(9,731		)	(10,761		)
Total long-term debt	$	705,269		$	489,239

Summary of Covenant Compliance

The covenants, as defined in the Amended and Restated Credit Facility, include requirements to comply with the following financial ratios:

Financial Covenant	Required Ratio
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than	1.0	to	1.0
Ratio of debt to EBITDAX, as defined in the credit agreement	Not greater than	4.0	to	1.0

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Subsequent Events

9 Months Ended

Sep. 30, 2019

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Proposed Merger of Jagged Peak with Parsley Energy, Inc.

On October 14, 2019, Jagged Peak entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Parsley Energy, Inc., a Delaware corporation (“Parsley”), and Jackal Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of Parsley (“Merger Sub”).

The closing of the Merger (as defined below) is expected to occur in the first quarter of 2020.

The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (1) Merger Sub will merge with and into Jagged Peak (the “Merger”), with Jagged Peak surviving the Merger as a wholly owned subsidiary of Parsley organized under the laws of the State of Delaware (the “Surviving Corporation”) and (2) following the Merger, the Surviving Corporation will merge with and into wholly owned limited liability company subsidiary of Parsley organized under the laws of the State of Delaware (“LLC Sub” and such merger, the “LLC Sub Merger”), with LLC Sub continuing as the surviving entity in the LLC Sub Merger and a wholly owned subsidiary of Parsley.

On the terms and subject to the conditions set forth in the Merger Agreement, upon consummation of the Merger, each share of Jagged Peak common stock, par value $0.01 per share, issued and outstanding immediately prior to the effective time of the Merger (excluding certain Excluded Shares and Non-Cancelled Shares (each, as defined in the Merger Agreement)) shall be converted into the right to receive from Parsley 0.447 fully-paid and non-assessable shares of Class A common stock, par value $0.01 per share, of Parsley (“Parsley Class A common stock”), with cash to be paid in lieu of fractional shares. Parsley’s Class A common stock is listed and trades on the New York Stock Exchange (the “NYSE”) under the ticker symbol PE.

The completion of the Merger is subject to certain customary mutual conditions, including (i) the receipt of the required approvals from Jagged Peak’s and Parsley’s stockholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act and any other applicable antitrust laws, (iii) the absence of any governmental order or law that makes consummation of the Merger illegal or otherwise prohibited, (iv) Parsley’s registration statement on Form S-4 (the “Form S-4”) having been declared effective by the U.S. Securities and Exchange Commission (“SEC”) under the Securities Act of 1933, (v) Parsley Class A common stock issuable in connection with the Merger having been authorized for listing on the NYSE, upon official notice of issuance, and (vi) the receipt by each party of a customary opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the U.S. tax code. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the Merger Agreement.

The Merger Agreement contains termination rights for each of Jagged Peak and Parsley, including, among others, if the consummation of the Merger does not occur on or before May 14, 2020. Upon termination of the Merger Agreement under specified circumstances, Jagged Peak may be required to pay Parsley a termination fee equal to $57.4 million or transaction

expenses of $16.4 million. Upon termination of the Merger Agreement under specified circumstances, Parsley may be required to pay the Company a termination fee equal to $189.0 million or transaction expenses of $54.0 million.

On November 4, 2019, Parsley filed the Form S-4 to register the Parsley shares to be issued in the Merger. The Form S-4 is subject to review by the SEC, and Parsley may file one or more amendments to the Form S-4 in the future.

Additional information on the proposed Merger, including the Merger Agreement, is included in the Form 8-K/A filed with the SEC on October 15, 2019.

Waiver to Redetermination Scheduled On or Around October 1, 2019

Due to the pending Merger of the Company with Parsley, the Company received a waiver for the redetermination of the borrowing base of the Amended and Restated Credit Facility that was scheduled to occur on or around October 1, 2019. Based on the terms of the waiver, the Company’s next borrowing base redetermination is scheduled to occur by February 15, 2020.

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Debt - Narrative (Details) - USD ($)	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Long-term debt:
Principal Amount	$ 705,269,000	$ 489,239,000
Revolving Credit Facility | Senior secured revolving credit facility
Long-term debt:
Elected commitment amount	540,000,000.0	540,000,000.0
Principal Amount	215,000,000	0
Elected commitment borrowing capacity available	$ 325,000,000.0
Weighted average interest rate	3.80%
Senior Notes | 5.875% senior unsecured notes due 2026
Long-term debt:
Principal Amount	$ 500,000,000	500,000,000
Interest rate	5.875%
Face amount of debt	$ 500,000,000.0
Redemption price percent	101.00%
Jagged Peak Energy LLC (JPE LLC) | Revolving Credit Facility | The Credit Facility
Long-term debt:
Current borrowing capacity	$ 900,000,000.0	$ 900,000,000.0

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Equity-based Compensation - Stock Units Activity (Details) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($) $ / shares shares
Incentive unit awards
Units
Unvested beginning balance (in shares)	5,397,555
Awards Granted (in shares)	28,991
Vested (in shares)	(2,598,796)
Forfeited (in shares)	(28,991)
Unvested ending balance (in shares)	2,798,759
Weighted average grant-date fair value (in usd per shares) | $ / shares	$ 8.27
Compensation costs remaining | $	$ 3.5
Weighted average remaining period	1 year 7 months 6 days
Restricted stock unit awards
Units
Unvested beginning balance (in shares)	871,119
Awards Granted (in shares)	1,232,503
Vested (in shares)	(291,704)
Forfeited (in shares)	(137,510)
Unvested ending balance (in shares)	1,674,408
Weighted average grant-date fair value (in usd per shares) | $ / shares	$ 10.18
Compensation costs remaining | $	$ 13.8
Weighted average remaining period	2 years 1 month 6 days
Performance stock unit awards
Units
Unvested beginning balance (in shares)	691,363
Awards Granted (in shares)	657,664
Vested (in shares)	0
Forfeited (in shares)	(135,299)
Unvested ending balance (in shares)	1,213,728
Weighted average grant-date fair value (in usd per shares) | $ / shares	$ 12.63
Compensation costs remaining | $	$ 9.5
Weighted average remaining period	1 year 9 months 18 days
Incentive Unit Awards Fully Expensed
Units
Unvested ending balance (in shares)	2,433,821
Nonemployee Director | Restricted stock unit awards
Units
Compensation costs remaining | $	$ 0.5
Weighted average remaining period	7 months 6 days

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Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ 8,597	$ (7,315)	$ (5,986)	$ 14,737
Effective tax rate	22.00%	21.60%	21.10%	(239.60%)

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Leases - Operating Lease Future Minimum Payments Under Previous Guidance (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Leases [Abstract]
2019	$ 1,547
2020	1,539
2021	1,553
2022	1,559
2023	1,589
Thereafter	7,378
Total	$ 15,165

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Leases - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Lessee, Lease, Description [Line Items]
Operating lease not yet commenced, term	3 years 8 months 12 days		3 years 8 months 12 days
Expected cash payments for operating lease not yet commenced.	$ 1.5
Operating leases, rent expense, net		$ 0.5		$ 1.8
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease terms of operating leases			6 months
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease terms of operating leases			8 years 8 months 12 days

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning balance	$ 2,072
Liabilities incurred and assumed	902
Liability settlements	(318)
Revisions of estimated liabilities	717
Accretion	159
Asset retirement obligation, ending balance	3,532
Less current portion of asset retirement obligations	(923)
Long-term asset retirement obligations	$ 2,609	$ 1,946

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Fair Value Measurements

9 Months Ended

Sep. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Financial assets and liabilities are measured at fair value on a recurring basis. Nonfinancial assets and liabilities, such as the initial measurement of asset retirement obligations 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 nine months ended September 30, 2019.

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)	September 30, 2019		December 31, 2018
Assets from commodity derivative contracts	$	61,967	$	134,991
Liabilities due to commodity derivative contracts	$	32,397	$	34,370

The fair value of the Company’s oil swaps and basis swaps is computed using discounted cash flows for the remaining duration of each commodity derivative instrument using the terms of the related contract. Inputs include published forward commodity price curves as of the date of the estimate. The Company compares these prices to the price parameters contained in its derivative 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 made using 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 balance sheets:

	September 30, 2019				December 31, 2018
(in thousands)	Principal Amount		Fair Value		Principal Amount		Fair Value
Long-term debt:
Senior secured revolving credit facility	$	215,000	$	215,000	$	—	$	—
5.875% senior unsecured notes due 2026	$	500,000	$	501,490	$	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 these inputs are classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes at September 30, 2019 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 considers 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Proved oil and natural gas property impairments	$	—	$	—	$	—	$	—
Unproved oil and natural gas property impairments (1)	31,817		—		32,763		53
	$	31,817	$	—	$	32,763	$	53

(1) Impairment of unproved oil and natural gas properties in 2019 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 2018 resulted from expirations of certain undeveloped leases.

Asset retirement obligations. The inception value and new layers resulting from upward revisions of the Company’s asset retirement obligations 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.

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Equity-based Compensation

9 Months Ended

Sep. 30, 2019

Share-based Payment Arrangement [Abstract]

Equity-based Compensation

Equity-based Compensation

Equity-based compensation expense, for each type of equity-based award, was as follows for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Incentive unit awards	$	856	$	609	$	2,050	$	75,767
Restricted stock unit awards	1,624		883		4,520		2,996
Performance stock unit awards	1,403		1,016		3,987		1,513
Restricted stock unit awards issued to nonemployee directors	215		106		468		395
Equity-based compensation expense	$	4,098	$	2,614	$	11,025	$	80,671

Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated statements of operations, will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, modification of awards, employee forfeitures and the timing of the awards.

For the nine months ended September 30, 2018, equity-based compensation expense included (1) $71.3 million related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO and (2) the reversal of equity-based compensation expense associated with awards that were forfeited during the nine months ended September 30, 2018, notably performance stock unit (“PSU”) awards forfeited by former executive officers. As the Company’s policy is to recognize forfeitures as they occur, previously recognized expense on unvested awards is reversed at the date of forfeiture.

The following table summarizes the Company’s award activity for incentive units, restricted stock units (“RSU”) and PSUs for the nine months ended September 30, 2019:

	Incentive Units (2)		RSUs		PSUs
Unvested at December 31, 2018	5,397,555		871,119		691,363
Awards Granted (1)	28,991		1,232,503		657,664
Vested	(2,598,796	)	(291,704	)	—
Forfeited	(28,991	)	(137,510	)	(135,299	)
Unvested at September 30, 2019	2,798,759		1,674,408		1,213,728

(1) The weighted average grant-date fair value was $8.27 for incentive units, $10.18 for RSUs and $12.63 for PSUs. The weighted average grant-date fair value for PSUs was calculated using a Monte Carlo simulation.

(2) Included in the unvested incentive units at September 30, 2019 are 2,433,821 units for which equity-based compensation expense has been accelerated and fully recognized.

The following table reflects the future equity-based compensation expense to be recorded for each type of award that was outstanding at September 30, 2019:

	Incentive Units		RSUs (1)		PSUs
Compensation costs remaining at September 30, 2019 (in millions)	$	3.5	$	13.8	$	9.5
Weighted average remaining period at September 30, 2019 (in years)	1.6		2.1		1.8

(1)

The remaining compensation cost at September 30, 2019 for the nonemployee director RSUs was $0.5 million, with a weighted average remaining period of 0.6 years.

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2019

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table summarizes fees paid to Oryx and Phoenix for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Oryx via 3rd party shipper (1)	$	—	$	6,435	$	14,041	$	16,719
Oryx (2)	$	32	$	140	$	548	$	440
Phoenix (3)	$	17	$	98	$	68	$	319

(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 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 balance sheets. The Company also received $45 thousand from Oryx during the nine months ended September 30, 2019 related to pipeline easements and right of way agreements.

(3) Fees paid to Phoenix are capitalized to proved properties on the consolidated balance sheets.

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Significant Accounting Policies and Related Matters - Schedule of New Accounting Pronouncements and Changes in Accounting Principles (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Jan. 01, 2019	Dec. 31, 2018
Leases [Abstract]
Operating lease right-of-use assets	$ 47,489	$ 73,413
Current operating lease liabilities	36,263	35,043
Long-term operating lease liabilities	15,519	42,814
Other long-term liabilities	$ 0	0	$ 4,444
Accounting Standards Update 2016-02
Leases [Abstract]
Operating lease right-of-use assets		73,413
Current operating lease liabilities		35,043
Long-term operating lease liabilities		42,814
Other long-term liabilities		(4,444)
Previous Accounting Guidance
Leases [Abstract]
Operating lease right-of-use assets		0
Current operating lease liabilities		0
Long-term operating lease liabilities		0
Other long-term liabilities		$ 4,444

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Derivative Instruments - Narrative (Details)	Sep. 30, 2019 counterparty
Commodity contracts
Derivative [Line Items]
Number of counterparties	7

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2019

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:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share amounts)	2019		2018			2019			2018
Net income (loss) attributable to common stock	$	30,558	$	(26,566	)	$	(22,423	)	$	(20,888	)
Basic weighted average shares outstanding	213,403		213,180			213,349			213,109
Dilutive unvested RSUs	35		—			—			—
Dilutive unvested PSUs	262		—			—			—
Diluted weighted average shares outstanding	213,700		213,180			213,349			213,109
Net income (loss) per common share:
Basic	$	0.14	$	(0.12	)	$	(0.11	)	$	(0.10	)
Diluted	$	0.14	$	(0.12	)	$	(0.11	)	$	(0.10	)

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. These shares could dilute basic earnings per share in future periods.

	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands)	2019	2018	2019	2018
Number of antidilutive units: (1)
Antidilutive unvested RSUs	1,575	791	1,455	721
Antidilutive unvested PSUs	225	603	1,076	496

(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.

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Significant Accounting Policies and Related Matters (Tables)

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Schedule of Accounts Receivable

At September 30, 2019 and December 31, 2018, accounts receivable was comprised of the following:

(in thousands)	September 30, 2019		December 31, 2018
Oil and gas sales	$	54,233	$	40,465
Joint interest	5,172		14,058
Other	2,657		6,663
Total accounts receivable	$	62,062	$	61,186

Property, Plant and Equipment

A summary of the Company’s oil and natural gas properties, net is as follows:

(in thousands)	September 30, 2019			December 31, 2018
Proved oil and natural gas properties	$	2,244,576		$	1,746,766
Unproved oil and natural gas properties	133,189			158,732
Total oil and natural gas properties	2,377,765			1,905,498
Less: Accumulated depletion	(569,733		)	(386,883		)
Total oil and natural gas properties, net	$	1,808,032		$	1,518,615

Schedule of Accrued Liabilities

The components of accrued liabilities are shown below:

(in thousands)	September 30, 2019		December 31, 2018
Accrued capital expenditures	$	80,153	$	74,688
Accrued production and ad valorem taxes	12,765		7,802
Accrued interest	12,645		4,896
Royalties payable	9,684		19,964
Accrued LOE	9,944		8,014
Accrued accounts payable	1,454		5,941
Other current liabilities	10,210		8,707
Total accrued liabilities	$	136,855	$	130,012

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

The impact to the opening January 1, 2019 consolidated balance sheets was as follows:

(in thousands)	Opening Balances as of January 1, 2019		Adoption of ASC 842			As Adjusted at January 1, 2019
Operating lease right-of-use assets (1)	$	—	$	73,413		$	73,413
Current operating lease liabilities (1)	$	—	$	35,043		$	35,043
Long-term operating lease liabilities (1)	—		42,814			42,814
Other long-term liabilities (2)	4,444		(4,444		)	—

(1) Represents the recognition of operating lease ROU assets and the associated lease liabilities.

(2) Represents the derecognition of deferred rent and leasehold incentives that were accounted for under ASC 840.

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
REVENUES
Revenues	$ 150,065	$ 155,378	$ 426,417	$ 443,107
OPERATING EXPENSES
Lease operating expenses	17,554	11,184	46,758	31,390
Production and ad valorem taxes	11,263	9,517	32,100	26,437
Exploration	3	23	3	24
Depletion, depreciation, amortization and accretion	66,069	57,660	186,365	160,552
Impairment of unproved oil and natural gas properties	31,817	0	32,763	53
General and administrative expenses (including equity-based compensation of $4,098 and $2,614 for the three months ended September 30, 2019 and 2018, respectively, and $11,025 and $80,671 for the nine months ended September 30, 2019 and 2018, respectively)	13,669	12,321	40,141	109,471
Other operating expenses	0	19	3,206	65
Total operating expenses	140,375	90,724	341,336	327,992
INCOME (LOSS) FROM OPERATIONS	9,690	64,654	85,081	115,115
OTHER INCOME (EXPENSE)
Gain (loss) on commodity derivatives	39,421	(96,516)	(85,702)	(110,426)
Interest expense, net	(9,974)	(8,256)	(27,683)	(17,095)
Gain (Loss) on Disposition of Oil and Gas Property	0	6,225	0	6,225
Other, net	18	12	(105)	30
Total other income (expense)	29,465	(98,535)	(113,490)	(121,266)
INCOME (LOSS) BEFORE INCOME TAX	39,155	(33,881)	(28,409)	(6,151)
Income tax expense (benefit)	8,597	(7,315)	(5,986)	14,737
NET INCOME (LOSS)	$ 30,558	$ (26,566)	$ (22,423)	$ (20,888)
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.14	$ (0.12)	$ (0.11)	$ (0.10)
Diluted (in dollars per share)	$ 0.14	$ (0.12)	$ (0.11)	$ (0.10)
Weighted average common shares outstanding:
Basic (in shares)	213,403	213,180	213,349	213,109
Diluted (in shares)	213,700	213,180	213,349	213,109
Oil sales
REVENUES
Revenues	$ 147,710	$ 141,598	$ 416,824	$ 410,935
Natural gas sales
REVENUES
Revenues	727	2,552	904	7,765
NGL sales
REVENUES
Revenues	1,628	10,814	8,680	23,721
Other operating revenues
REVENUES
Other operating revenues	$ 0	$ 414	$ 9	$ 686

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Organization, Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2019

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.

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”). Additional background on the Company, its IPO and details of the ownership of the Company are available in the Company's Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”).

Basis of Presentation

The accompanying unaudited interim consolidated 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”) for interim financial information, and should be read in conjunction with the financial statements, summary of significant accounting policies and footnotes included in the 2018 Form 10-K. Accordingly, certain disclosures required by GAAP and normally included in Annual Reports on Form 10-K have been condensed or omitted from this report; however, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in the 2018 Form 10-K. All significant intercompany balances and transactions have been eliminated.

It is the opinion of management that all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identical to its comprehensive income or loss. Operating results for the periods presented are not necessarily indicative of expected results for the full year because of the impact of fluctuations in prices received for oil, natural gas and NGLs, expected production changes due to development activities, natural production declines, the uncertainty of exploration and development drilling results, the fair value of derivative instruments and other factors.

Certain prior year amounts have been reclassified to conform to the current presentation.

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Subsequent Events (Details) $ / shares in Units, $ in Millions	Oct. 14, 2019 USD ($) $ / shares	Sep. 30, 2019 $ / shares	Dec. 31, 2018 $ / shares
Subsequent Event [Line Items]
Common stock par value (in dollars per share) | $ / shares		$ 0.01	$ 0.01
Subsequent Event | Forecast | Parsley Energy, Inc.
Subsequent Event [Line Items]
Common stock par value (in dollars per share) | $ / shares	$ 0.01
Conversion of Parsley Energy, Inc. shares (in shares)	0.447
Termination fee payable by Jagged Peak Energy upon cancellation of merger agreement	$ 57.4
Transaction expenses payable by Jagged Peak Energy upon cancellation of merger agreement	16.4
Termination fee payable by Parsley Energy upon cancellation of merger agreement	189.0
Transaction expenses payable by Parsley Energy upon cancellation of merger agreement	$ 54.0

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Equity-based Compensation - Share-based Compensation Expense (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based compensation expense	$ 4,098	$ 2,614	$ 11,025	$ 80,671
Incentive unit awards
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based compensation expense	856	609	2,050	75,767
Restricted stock unit awards
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based compensation expense	1,624	883	4,520	2,996
Performance stock unit awards
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based compensation expense	1,403	1,016	3,987	1,513
Restricted stock unit awards issued to nonemployee directors
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based compensation expense	$ 215	$ 106	$ 468	$ 395

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Earnings Per Share - Antidilutive Securities (Details) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Antidilutive unvested RSUs
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)	1,575	791	1,455	721
Antidilutive unvested PSUs
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)	225	603	1,076	496

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Leases - Operating Lease Liability Maturity (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Jan. 01, 2019
Leases [Abstract]
Remainder of 2019	$ 9,450
2020	33,428
2021	1,547
2022	1,558
2023	1,589
Thereafter	7,378
Operating lease payments	54,950
Less: amount of lease payments representing interest	(3,168)
Present value of future minimum lease payments	51,782
Less: current operating lease liabilities	(36,263)	$ (35,043)
Long-term operating lease liabilities	$ 15,519	$ 42,814

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Fair Value Measurements - Fair Value of Other Financial Instruments (Details) - USD ($)	Sep. 30, 2019	Dec. 31, 2018
Long-term debt:
Principal Amount	$ 705,269,000	$ 489,239,000
Revolving Credit Facility | Senior secured revolving credit facility
Long-term debt:
Principal Amount	215,000,000	0
Level 2 | Revolving Credit Facility | Senior secured revolving credit facility
Long-term debt:
Principal Amount	215,000,000	0
Fair value, senior secured revolving credit facility	215,000,000	0
Senior Notes | 5.875% senior unsecured notes due 2026
Long-term debt:
Principal Amount	500,000,000	500,000,000
Senior Notes | Level 1 | 5.875% senior unsecured notes due 2026
Long-term debt:
Principal Amount	500,000,000	500,000,000
Fair value, 5.875% senior unsecured notes due 2026	$ 501,490,000	$ 466,250,000

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Significant Accounting Policies and Related Matters - Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Accounting Policies [Abstract]
Proved oil and natural gas properties	$ 2,244,576		$ 2,244,576		$ 1,746,766
Unproved oil and natural gas properties	133,189		133,189		158,732
Total oil and natural gas properties	2,377,765		2,377,765		1,905,498
Less: Accumulated depletion	(569,733)		(569,733)		(386,883)
Total oil and gas properties, net	1,808,032		1,808,032		$ 1,518,615
Depletion of oil and gas properties	$ 65,600	$ 57,200	$ 184,900	$ 159,000

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Derivative Instruments - Gains (Losses) in Earnings (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Derivative [Line Items]
Net gain (loss) on settled derivative instruments			$ 14,651	$ 33,705
Gain (loss) on derivative instruments, net	$ 39,421	$ (96,516)	(85,702)	(110,426)
Commodity contracts
Derivative [Line Items]
Net gain (loss) on settled derivative instruments	(3,484)	(6,347)	(14,651)	(33,705)
Net gain (loss) from the change in fair value of open derivative instruments	42,905	(90,169)	(71,051)	(76,721)
Gain (loss) on derivative instruments, net	$ 39,421	$ (96,516)	$ (85,702)	$ (110,426)

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Income Taxes

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs.

Income tax expense was as follows for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2019			2018			2019			2018
Income tax expense (benefit)	$	8,597		$	(7,315	)	$	(5,986	)	$	14,737
Effective tax rate	22.0		%	21.6		%	21.1		%	(239.6		)%

For the nine months ended September 30, 2018, the Company’s effective tax rate differed from the federal statutory rate of 21% primarily due to nondeductible equity-based compensation related to incentive unit awards allocated at the time of the IPO, and permanent differences on vested equity-based compensation awards.

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Derivative Instruments

9 Months Ended

Sep. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

Objectives and Strategies

The Company is exposed to fluctuations in commodity prices received for its oil and natural gas production. To mitigate the volatility in its expected operating cash flows, the Company hedges a portion of its crude oil sales through derivative instruments. The Company does not use these instruments for speculative or trading purposes.

Commodity Derivatives

In an effort to reduce the variability of the Company’s cash flows, the Company hedges the commodity prices associated with a portion of its expected future oil volumes by entering into the following types of instruments:

Swaps. The Company receives a 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 Swaps. These instruments establish a fixed price differential between Cushing WTI prices and Midland WTI prices for the notional volumes contracted. The Company receives the fixed price differential and pays the floating market price differential to the counterparty.

The following table summarizes the Company’s derivative contracts as of September 30, 2019:

Contract Period	Volumes (MBbls)	Wtd Avg Price ($/Bbl)
Oil Swaps: (1)
Fourth quarter 2019	1,932	$	59.95
Year ending December 31, 2020	7,320	$	58.25
Oil Basis Swaps: (2)
Fourth quarter 2019	2,300	$	(4.79	)
Year ending December 31, 2020	9,516	$	(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.

Counterparty Risk

By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. 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.

At September 30, 2019, the Company had commodity derivative contracts with seven counterparties, all of which were lenders, or affiliates of 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.

Should the creditworthiness of the Company’s counterparties decline, under certain circumstances the Company may have a contractual right of offset against other amounts owed by the Company to the counterparty, but otherwise 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.

Financial Statement Presentation

The Company’s derivative instruments are carried at fair value on the consolidated balance sheets. The Company has elected to not apply hedge accounting; 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 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.

Consolidated Statements of Operations

The Company recognized the following gains (losses) on derivative instruments in its consolidated statements of operations for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2019			2018			2019			2018
Net gain (loss) on settled derivative instruments	$	(3,484	)	$	(6,347	)	$	(14,651	)	$	(33,705	)
Net gain (loss) from the change in fair value of open derivative instruments	42,905			(90,169		)	(71,051		)	(76,721		)
Gain (loss) on derivative instruments, net	$	39,421		$	(96,516	)	$	(85,702	)	$	(110,426	)

Consolidated Balance Sheets

The Company’s derivative instruments 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 balance sheets.

The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of September 30, 2019 and December 31, 2018 (in thousands):

As of September 30, 2019:	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	$	48,006	$	(25,639	)	$	22,367
Commodity contracts	Noncurrent assets - derivative instruments	13,961		(4,659		)	9,302
Total assets		$	61,967	$	(30,298	)	$	31,669
Liabilities
Commodity contracts	Current liabilities - derivative instruments	$	27,738	$	(25,639	)	$	2,099
Commodity contracts	Noncurrent liabilities - derivative instruments	4,659		(4,659		)	—
Total liabilities		$	32,397	$	(30,298	)	$	2,099

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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Commitments

There were no material changes in commitments during the first nine months of 2019. Please refer to Note 10, Commitments and Contingencies, in the 2018 Form 10-K for additional discussion.

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 any such current 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 September 30, 2019 and December 31, 2018, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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Leases - Operating Lease Supplemental Information (Details)	Sep. 30, 2019
Leases [Abstract]
Weighted average remaining lease term - operating leases (in years)	2 years 9 months 18 days
Weighted average discount rate - operating leases	4.20%

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Fair Value Measurements - Assets and liabilities measured on a nonrecurring basis (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unproved oil and natural gas property impairments	$ 31,817	$ 0	$ 32,763	$ 53
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	0
Unproved Oil And Gas Properties | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unproved oil and natural gas property impairments	$ 31,817	$ 0	$ 32,763	$ 53

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Significant Accounting Policies and Related Matters - Schedule of Accounts Receivable (Details) - USD ($)	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 62,062,000		$ 61,186,000
Reserve for doubtful accounts	0		0
Bad debt expense	0	$ 0
Oil and gas sales
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	54,233,000		40,465,000
Joint interest
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	5,172,000		14,058,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 2,657,000		$ 6,663,000

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Derivative Instruments - Schedule of Derivatives (Details) - Not Designated as Hedging Instrument	9 Months Ended
	Sep. 30, 2019 $ / bbl bbl
Fourth quarter 2019
Derivative [Line Items]
Volumes (MBbls) | bbl	1,932,000
Wtd Avg Price ($/Bbl), Oil swaps | $ / bbl	59.95
Year ending December 31, 2020
Derivative [Line Items]
Volumes (MBbls) | bbl	7,320,000
Wtd Avg Price ($/Bbl), Oil swaps | $ / bbl	58.25
Fourth quarter 2019
Derivative [Line Items]
Volumes (MBbls) | bbl	2,300,000
Wtd Avg Price ($/Bbl), Oil basis swaps | $ / bbl	(4.79)
Year ending December 31, 2020
Derivative [Line Items]
Volumes (MBbls) | bbl	9,516,000
Wtd Avg Price ($/Bbl), Oil basis swaps | $ / bbl	(1.31)

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Related Party Transactions

9 Months Ended

Sep. 30, 2019

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

As a result of Quantum’s significant ownership interest in the Company, the Company identified Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”) and Phoenix Lease Services, LLC (“Phoenix”) as related parties. These entities are considered related parties as Quantum owns an interest, either directly or indirectly, in each entity.

During the second quarter of 2019, Quantum sold its interest in Oryx, at which point Oryx ceased to be a related party. As a result, transactions with Oryx that occurred subsequent to the date of sale are no longer considered related party transactions and are not included in the below disclosures.

The following table summarizes fees paid to Oryx and Phoenix for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Oryx via 3rd party shipper (1)	$	—	$	6,435	$	14,041	$	16,719
Oryx (2)	$	32	$	140	$	548	$	440
Phoenix (3)	$	17	$	98	$	68	$	319

(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 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 balance sheets. The Company also received $45 thousand from Oryx during the nine months ended September 30, 2019 related to pipeline easements and right of way agreements.

(3) Fees paid to Phoenix are capitalized to proved properties on the consolidated balance sheets.

At September 30, 2019 the Company had no outstanding payables to these related parties. At December 31, 2018, the Company had outstanding payables of $2.6 million to these related parties. See Note 11, Related Party Transactions, in the 2018 Form 10-K for more information.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The following table summarizes the changes in the carrying amount of the asset retirement obligations for the nine months ended September 30, 2019. The current portion of the asset retirement obligation liability is included in accrued liabilities on the consolidated balance sheets.

(in thousands)
Asset retirement obligations at January 1, 2019	$	2,072
Liabilities incurred and assumed	902
Liability settlements	(318		)
Revisions of estimated liabilities	717
Accretion	159
Asset retirement obligations at September 30, 2019	3,532
Less current portion of asset retirement obligations	(923		)
Long-term asset retirement obligations	$	2,609

During the nine months ended September 30, 2019, the Company recognized revisions of estimated liabilities totaling $0.7 million which were due to changes in estimated abandonment timing and costs.

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Debt

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Debt

Debt

The Company’s debt consisted of the following at September 30, 2019 and December 31, 2018:

(in thousands)	September 30, 2019			December 31, 2018
Senior secured revolving credit facility	$	215,000		$	—
5.875% senior unsecured notes due 2026	500,000			500,000
Debt issuance costs on senior unsecured notes	(9,731		)	(10,761		)
Total long-term debt	$	705,269		$	489,239

Senior Secured Revolving Credit Facility

At December 31, 2018, the Company’s amended and restated credit facility, as amended (the “Amended and Restated Credit Facility”), had a borrowing base of $900.0 million with elected commitments of $540.0 million and nothing outstanding.

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:

Financial Covenant	Required Ratio
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than	1.0	to	1.0
Ratio of debt to EBITDAX, as defined in the credit agreement	Not greater than	4.0	to	1.0

As of September 30, 2019, the Company was in compliance with the financial covenants under its Amended and Restated Credit Facility .

As of September 30, 2019, the borrowing base and elected commitments remained at $900.0 million and $540.0 million, respectively, and the Company had $215.0 million outstanding and $325.0 million of elected commitments available. The weighted-average interest rate as of September 30, 2019 was 3.80%.

5.875% Senior Unsecured Notes due 2026

JPE LLC has $500.0 million aggregate principal amount of 5.875% senior unsecured notes that mature on May 1, 2026 (the “Senior Notes”). Interest is payable on the Senior Notes semi-annually in arrears on each May 1 and November 1.

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 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 March 2019 the Company completed 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).

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, pursuant to a change of control offer made by the Company pursuant to the terms of the indenture governing the Senior Notes.

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.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense was as follows for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2019			2018			2019			2018
Income tax expense (benefit)	$	8,597		$	(7,315	)	$	(5,986	)	$	14,737
Effective tax rate	22.0		%	21.6		%	21.1		%	(239.6		)%

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

The following table summarizes the Company’s derivative contracts as of September 30, 2019:

Contract Period	Volumes (MBbls)	Wtd Avg Price ($/Bbl)
Oil Swaps: (1)
Fourth quarter 2019	1,932	$	59.95
Year ending December 31, 2020	7,320	$	58.25
Oil Basis Swaps: (2)
Fourth quarter 2019	2,300	$	(4.79	)
Year ending December 31, 2020	9,516	$	(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 Company recognized the following gains (losses) on derivative instruments in its consolidated statements of operations for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2019			2018			2019			2018
Net gain (loss) on settled derivative instruments	$	(3,484	)	$	(6,347	)	$	(14,651	)	$	(33,705	)
Net gain (loss) from the change in fair value of open derivative instruments	42,905			(90,169		)	(71,051		)	(76,721		)
Gain (loss) on derivative instruments, net	$	39,421		$	(96,516	)	$	(85,702	)	$	(110,426	)

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 September 30, 2019 and December 31, 2018 (in thousands):

As of September 30, 2019:	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	$	48,006	$	(25,639	)	$	22,367
Commodity contracts	Noncurrent assets - derivative instruments	13,961		(4,659		)	9,302
Total assets		$	61,967	$	(30,298	)	$	31,669
Liabilities
Commodity contracts	Current liabilities - derivative instruments	$	27,738	$	(25,639	)	$	2,099
Commodity contracts	Noncurrent liabilities - derivative instruments	4,659		(4,659		)	—
Total liabilities		$	32,397	$	(30,298	)	$	2,099

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

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Significant Accounting Policies and Related Matters

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Significant Accounting Policies and Related Matters

Significant Accounting Policies and Related Matters

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 2, Significant Accounting Policies and Related Matters, to the Company’s consolidated financial statements in its 2018 Form 10-K, and are supplemented by the notes to the consolidated financial statements in this Quarterly Report on Form 10-Q. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in these notes to the consolidated financial statements.

Use of Estimates

In the course of preparing the consolidated 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 financial statements include, among other things, (1) oil and natural gas reserve quantities, which impact depletion of oil and natural gas properties and evaluation and measurement of any impairment of proved oil and natural gas properties, (2) impairment of unproved oil and natural gas properties, which includes assumptions about future development and lease renewal, commodity price outlooks and prevailing market rates, (3) accrued operating and capital costs, (4) asset retirement obligation timing and costs, (5) lease terms and incremental borrowing rates used in the determination of lease assets and liabilities, (6) measurement of equity-based compensation, (7) fair value of derivative instruments, (8) deferred income taxes and (9) disclosure of commitments and contingencies. Changes in these estimates and assumptions could have a significant impact on results in future periods.

Revenue Recognition

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 from the Delaware Basin. The Company believes the disaggregation of revenues into oil sales, natural gas sales and NGL sales, as seen on the consolidated statements of operations, is an appropriate level of detail for its primary activity.

Contract Assets and Liabilities. The Company’s performance obligations for its contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company did not have any contract assets or liabilities as of September 30, 2019 and December 31, 2018.

Performance Obligations. 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. 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.

Accounts Receivable

At September 30, 2019 and December 31, 2018, accounts receivable was comprised of the following:

(in thousands)	September 30, 2019		December 31, 2018
Oil and gas sales	$	54,233	$	40,465
Joint interest	5,172		14,058
Other	2,657		6,663
Total accounts receivable	$	62,062	$	61,186

At September 30, 2019 and December 31, 2018, the Company did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented.

Oil and Natural Gas Properties

A summary of the Company’s oil and natural gas properties, net is as follows:

(in thousands)	September 30, 2019			December 31, 2018
Proved oil and natural gas properties	$	2,244,576		$	1,746,766
Unproved oil and natural gas properties	133,189			158,732
Total oil and natural gas properties	2,377,765			1,905,498
Less: Accumulated depletion	(569,733		)	(386,883		)
Total oil and natural gas properties, net	$	1,808,032		$	1,518,615

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 three months ended September 30, 2019 and 2018, the Company recorded depletion for oil and natural gas properties of $65.6 million and $57.2 million, respectively. For the nine months ended September 30, 2019 and 2018, the Company recorded depletion for oil and natural gas properties of $184.9 million and $159.0 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated statements of operations.

Leases

Following the adoption of Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) on January 1, 2019, the Company determines if an arrangement is a lease at inception of the contract. Operating lease right-of-use (“ROU”) assets and operating lease liabilities are recognized based on the present value of the future lease payments over the lease term at commencement date. For leases that do not provide implicit rates, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Operating lease ROU assets exclude lease incentives and initial direct costs incurred. Operating lease cost is recognized on a straight-line basis over the lease term. The Company currently does not have any finance leases.

The Company has lease agreements with lease and non-lease components, which are all accounted for as a single lease component.

Short-term leases have a term of 12 months or less. The Company recognizes short-term lease cost based on usage of the asset over the lease term and does not record a ROU asset or lease liability for such leases.

The Company monitors for events or changes in circumstances that may require a reassessment or impairment of its leases, at which time the Company's ROU assets for operating leases may be reduced by impairment losses. 

Accrued Liabilities

The components of accrued liabilities are shown below:

(in thousands)	September 30, 2019		December 31, 2018
Accrued capital expenditures	$	80,153	$	74,688
Accrued production and ad valorem taxes	12,765		7,802
Accrued interest	12,645		4,896
Royalties payable	9,684		19,964
Accrued LOE	9,944		8,014
Accrued accounts payable	1,454		5,941
Other current liabilities	10,210		8,707
Total accrued liabilities	$	136,855	$	130,012

Recent Accounting Pronouncements

Recently Adopted Accounting Standards

Leases. In February 2016, the Financial Accounting Standards Board (“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. ASU 2016-02 retains a distinction between operating and finance leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. Entities are required to recognize operating or finance leases as ROU assets and lease liabilities on the balance sheet as well as disclose key information about leasing arrangements in the notes to the financial statements. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. This ASU does not apply to leases of mineral rights to explore for or use oil and natural gas.

The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective approach as permitted under ASU 2018-11, which allows the Company to apply the legacy lease guidance and disclosure requirements (“ASC 840”) in the comparative periods presented for the year of adoption. The adoption did not require an adjustment to opening retained earnings for a cumulative effect adjustment.

As part of the adoption, the Company elected the short-term lease recognition policy election for all leases that qualify, and as such, no ROU assets or lease liabilities will be recorded on the balance sheet when the term of the lease is less than 12 months. The Company also elected the following practical expedients:

•the package of transition practical expedients, permitting the Company to not reassess its prior conclusions about lease identification, lease classification and initial direct costs;

•the practical expedient pertaining to land easements, which allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way; and

•the practical expedient to not separate lease and non-lease components.

The new lease standard impacted the Company’s consolidated balance sheets as a result of the ROU assets and operating lease liabilities but did not impact its consolidated statements of operations or consolidated statements of cash flows. The Company currently has no finance leases. The impact to the opening January 1, 2019 consolidated balance sheets was as follows:

(in thousands)	Opening Balances as of January 1, 2019		Adoption of ASC 842			As Adjusted at January 1, 2019
Operating lease right-of-use assets (1)	$	—	$	73,413		$	73,413
Current operating lease liabilities (1)	$	—	$	35,043		$	35,043
Long-term operating lease liabilities (1)	—		42,814			42,814
Other long-term liabilities (2)	4,444		(4,444		)	—

(1) Represents the recognition of operating lease ROU assets and the associated lease liabilities.

(2) Represents the derecognition of deferred rent and leasehold incentives that were accounted for under ASC 840.

Adoption of the new standard did not impact the Company’s previously reported consolidated balance sheets, results of operations, cash flows statements or statements of changes in equity.

For more information on the Company’s leases, refer to Note 10, Leases.

Accounting Standards Not Yet Adopted

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 current 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 will be applied using a modified retrospective approach which may result 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 not been significant, and the Company does not believe the adoption of ASU 2016-13 will have a material impact on its consolidated financial statements.

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Cover page - shares	9 Months Ended
	Sep. 30, 2019	Nov. 01, 2019
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
Document Transition Report	false
Entity File Number	001-37995
Entity Registrant Name	Jagged Peak Energy Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	81-3943703
Entity Address, Address Line One	1401 Lawrence Street, Suite 1800
Entity Address, City or Town	Denver,
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80202
City Area Code	720
Local Phone Number	215-3700
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Title of 12(b) Security	Common stock, par value $0.01 per share
Trading Symbol	JAG
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		213,413,380
Document Fiscal Year Focus	2019
Amendment Flag	false
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001685715
Current Fiscal Year End Date	--12-31

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CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Statement of Financial Position [Abstract]
Equity-based compensation	$ 4,098	$ 2,614	$ 11,025	$ 80,671

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Debt - Summary Of Covenant Compliance (Details) - Senior secured revolving credit facility - Revolving Credit Facility	9 Months Ended
	Sep. 30, 2019
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement (not less than)	1.0
Ratio of debt to EBITDAX, as defined in the credit agreement (not greater than)	4.0

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Earnings Per Share - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share [Line Items]
Net income (loss) attributable to common stock	$ 30,558	$ 41,907	$ (94,888)	$ (26,566)	$ 45,081	$ (39,403)	$ (22,423)	$ (20,888)
Basic weighted average shares outstanding (in shares)	213,403			213,180			213,349	213,109
Diluted weighted average shares outstanding (in shares)	213,700			213,180			213,349	213,109
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.14			$ (0.12)			$ (0.11)	$ (0.10)
Diluted (in dollars per share)	$ 0.14			$ (0.12)			$ (0.11)	$ (0.10)
Restricted stock unit awards
Earnings Per Share [Line Items]
Dilutive unvested units (in shares)	35			0			0	0
Performance stock unit awards
Earnings Per Share [Line Items]
Dilutive unvested units (in shares)	262			0			0	0