Jagged Peak Energy Inc. - FORM 10-Q

Jagged Peak Energy Inc. - FORM 10-Q - November 8, 2017

Attached files

Attached files

Jagged Peak Energy Inc. Reports

file	filename
EX-32.2 - EXHIBIT 32.2 - Jagged Peak Energy Inc.	exhibit322q32017.htm
EX-32.1 - EXHIBIT 32.1 - Jagged Peak Energy Inc.	exhibit321q32017.htm
EX-31.2 - EXHIBIT 31.2 - Jagged Peak Energy Inc.	exhibit312q32017.htm
EX-31.1 - EXHIBIT 31.1 - Jagged Peak Energy Inc.	exhibit311q32017.htm
EX-10.2 - EXHIBIT 10.2 - Jagged Peak Energy Inc.	debtamendmentno1q32017.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2017

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



1125 17th Street, Suite 2400 Denver, Colorado (Address of principal executive offices)				80202 (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 x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes x 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.

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. x

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

The registrant had 212,930,655 shares of common stock outstanding at November 3, 2017.

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TABLE OF CONTENTS



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 and Combined Balance Sheets as of September 30, 2017 and December 31, 2016	4

	Consolidated and Combined Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	5

	Consolidated and Combined Statement of Changes in Equity for the Nine Months Ended September 30, 2017	6

	Consolidated and Combined Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	7

	Notes to Consolidated and Combined Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37

Item 4.	Controls and Procedures	39

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

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

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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.

Spud. Commenced drilling operations on an identified location.

Unproved properties. Lease acreage with no proved reserves.

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.

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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, 2016, and in “Item 1A. Risk Factors” of this Quarterly Report.

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 2017 and 2018;


•	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;


•	our future drilling plans, including the number of wells anticipated to be spud in 2017 and the number of drilling rigs and fracturing fleets anticipated to be in operation in 2017, and anticipated well economics;


•	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;


•	our hedging strategy and results;


•	general economic conditions;


•	uncertainty regarding our future operating results; 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, 2016, and in “Item 1A. Risk Factors” of this Quarterly Report.

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.

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Should one or more of the risks or uncertainties described in 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.

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.

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PART I—FINANCIAL INFORMATION


Item 1.	Financial Statements

JAGGED PEAK ENERGY INC.

CONSOLIDATED AND COMBINED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)



	September 30,			December 31,
	2017			2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,900		$	11,727
Accounts receivable	35,088			10,327
Derivative instruments	5,515			—
Other current assets	4,147			3,412
Total current assets	48,650			25,466
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method	1,006,747			531,121
Accumulated depletion	(123,448		)	(57,529		)
Total oil and gas properties, net	883,299			473,592
Other property and equipment, net	6,499			3,001
Total property and equipment, net	889,798			476,593
OTHER NONCURRENT ASSETS
Unamortized debt issuance costs	2,537			1,503
Derivative instruments	5,170			—
Other assets	121			14,830
Total noncurrent assets	7,828			16,333
TOTAL ASSETS	$	946,276		$	518,392
LIABILITIES AND STOCKHOLDERS’ / MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	13,975		$	7,629
Accrued liabilities	106,488			39,225
Derivative instruments	8,820			9,567
Total current liabilities	129,283			56,421
LONG-TERM LIABILITIES
Senior secured revolving credit facility	35,000			132,000
Derivative instruments	2,490			3,287
Asset retirement obligations	690			448
Deferred income taxes	101,039			—
Other long-term liabilities	2,526			124
Total long-term liabilities	141,745			135,859
Commitments and contingencies
STOCKHOLDERS’ / MEMBERS’ EQUITY
Members' equity	—			346,098
Preferred stock, $0.01 par value, 50,000,000 shares authorized, no shares issued at September 30, 2017; no shares authorized or issued at December 31, 2016	—			—
Common stock, $0.01 par value; 1,000,000,000 shares authorized, 212,930,655 shares issued at September 30, 2017; no shares authorized or issued at December 31, 2016	2,129			—
Additional paid-in capital	762,340			—
Accumulated deficit	(89,221		)	(19,986		)
Total stockholders’ / members’ equity	675,248			326,112
TOTAL LIABILITIES AND STOCKHOLDERS’ / MEMBERS’ EQUITY	$	946,276		$	518,392

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

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JAGGED PEAK ENERGY INC.

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
REVENUES
Oil sales	$	62,585		$	20,332		$	147,738		$	47,215
Natural gas sales	2,939			731			5,697			1,450
NGL sales	4,860			819			9,041			2,023
Other operating revenues	67			182			414			957
Total revenues	70,451			22,064			162,890			51,645
OPERATING EXPENSES
Lease operating expenses	5,184			2,285			10,684			5,254
Gathering and transportation expenses	1,357			294			2,404			662
Production and ad valorem taxes	4,739			1,341			10,916			3,173
Exploration	6			—			14			2,474
Depletion, depreciation, amortization and accretion	30,851			11,152			67,224			29,430
Impairment of unproved oil and natural gas properties	257			7			365			317
General and administrative expenses (including equity-based compensation of $11,903 and $0 for the three months ended September 30, 2017 and 2016, respectively, and $431,642 and $0 for the nine months ended September 30, 2017 and 2016, respectively)	17,733			2,375			449,504			7,878
Other operating expenses	41			169			223			567
Total operating expenses	60,168			17,623			541,334			49,755
INCOME (LOSS) FROM OPERATIONS	10,283			4,441			(378,444		)	1,890
OTHER INCOME (EXPENSE)
Gain (loss) on commodity derivatives	(27,693		)	1,728			15,922			(8,208		)
Interest expense, net	(467		)	(759		)	(1,610		)	(1,471		)
Other, net	60			—			474			—
Total other income (expense)	(28,100		)	969			14,786			(9,679		)
INCOME (LOSS) BEFORE INCOME TAX	(17,817		)	5,410			(363,658		)	(7,789		)
Income tax expense (benefit)	(2,598		)	—			101,039			—
NET INCOME (LOSS)	(15,219		)	5,410			(464,697		)	(7,789		)
Less: Net loss attributable to Jagged Peak Energy LLC (predecessor)	—			5,410			(375,476		)	(7,789		)
NET INCOME (LOSS) ATTRIBUTABLE TO JAGGED PEAK ENERGY INC. STOCKHOLDERS	$	(15,219	)	$	—		$	(89,221	)	$	—

Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share:
Basic	$	(0.07	)				$	(0.42	)
Diluted	$	(0.07	)				$	(0.42	)

Weighted-average common shares outstanding:
Basic	212,931						212,933
Diluted	212,931						212,933

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

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JAGGED PEAK ENERGY INC.

CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

(in thousands)



	Members' Equity			Common Stock				Additional Paid-in Capital			Accumulated Deficit			Total Stockholders' Equity / Members' Equity
	Members' Equity			Shares		Amount		Additional Paid-in Capital			Accumulated Deficit			Total Stockholders' Equity / Members' Equity
BALANCE AT DECEMBER 31, 2016	$	346,098		—		$	—	$	—		$	(19,986	)	$	326,112
Deemed contribution - incentive unit compensation	364,314			—		—		—			—			364,314
Net income (loss) for the period prior to the corporate reorganization	—			—		—		—			(375,476		)	(375,476		)
Balance prior to corporate reorganization and initial public offering	710,412			—		—		—			(395,462		)	314,950
Issuance of common stock in corporate reorganization	(710,412		)	184,605		1,846		313,104			395,462			—
Issuance of common stock in initial public offering, net of offering costs	—			28,333		283		396,708			—			396,991
Common stock reacquired and retired	—			(7	)	—		(88		)	—			(88		)
Equity-based compensation	—			—		—		52,616			—			52,616
Net income (loss)	—			—		—		—			(89,221		)	(89,221		)
BALANCE AT SEPTEMBER 30, 2017	$	—		212,931		$	2,129	$	762,340		$	(89,221	)	$	675,248

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

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JAGGED PEAK ENERGY INC.

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)



	Nine Months Ended September 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(464,697	)	$	(7,789	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion expense	67,224			29,430
Management incentive unit advance	—			(14,712		)
Impairment of unproved oil and natural gas properties	365			317
Exploratory dry hole costs	—			1,192
Amortization of debt issuance costs	407			164
Deferred income taxes	101,039			—
Equity-based compensation	431,642			—
(Gain) loss on commodity derivatives	(15,922		)	8,208
Net cash receipts (payments) on settled derivatives	3,691			(1,159		)
Other	(123		)	(120		)
Change in operating assets and liabilities:
Accounts receivable and other current assets	(27,292		)	(545		)
Other assets	(3		)	11
Accounts payable and accrued liabilities	9,097			1,825
Net cash provided by operating activities	105,428			16,822
CASH FLOWS FROM INVESTING ACTIVITIES
Leasehold and acquisition costs	(60,627		)	(39,344		)
Development of oil and natural gas properties	(349,176		)	(84,809		)
Other capital expenditures	(3,332		)	(1,831		)
Net cash used in investing activities	(413,135		)	(125,984		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock in initial public offering, net of underwriting fees	401,625			—
Proceeds from common units issued	—			31,542
Proceeds from credit facility	45,000			70,000
Repayment of credit facility	(142,000		)	—
Debt issuance costs	(1,441		)	(1,030		)
Costs relating to initial public offering	(3,216		)	(95		)
Employee tax withholding for settlement of equity compensation awards	(88		)	—
Net cash provided by financing activities	299,880			100,417
NET CHANGE IN CASH AND CASH EQUIVALENTS	(7,827		)	(8,745		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	11,727			14,165
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3,900		$	5,420
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest	$	1,234		$	1,189
Cash paid for income taxes	—			—
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	102,031		$	22,853
Asset retirement obligations	488			(165		)
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Accrued offering costs	$	—		$	1,086

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

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined 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, a sub-basin of the Permian Basin of West Texas. The Company’s acreage is located on large, contiguous blocks in the adjacent counties of Winkler, Ward, Reeves and Pecos, with significant oil-in-place within multiple stacked hydrocarbon-bearing formations.

Corporate Reorganization and Initial Public Offering

Jagged Peak is a Delaware corporation formed in September 2016, as a wholly owned subsidiary of Jagged Peak Energy LLC (“JPE LLC”), a Delaware limited liability company formed in April 2013. JPE LLC was formed by an affiliate of Quantum Energy Partners (“Quantum”) and members of Jagged Peak’s management team. Jagged Peak was formed to become the holding company of JPE LLC in connection with Jagged Peak’s initial public offering (the “IPO”).

Immediately prior to the IPO, all capital interests and management incentive units (“MIUs”) in JPE LLC were converted into a single class of units which were then converted into common stock. Certain members of management and employees contributed a portion of common stock received upon the conversion of unvested or unallocated MIUs to JPE Management Holdings LLC, a limited liability company formed in connection with the IPO for the purpose of holding the unvested or unallocated common stock. Also immediately prior to the IPO, a corporate reorganization (the “corporate reorganization”) took place whereby Jagged Peak, initially formed as a subsidiary of JPE LLC, formed JPE Merger Sub LLC as a subsidiary. JPE LLC merged into JPE Merger Sub LLC, with JPE LLC as the surviving entity. As a result, JPE LLC became a wholly owned subsidiary of Jagged Peak. Prior to the corporate reorganization, Quantum owned 98.6% of the membership interests of JPE LLC. Immediately following the corporate reorganization and IPO, Quantum owned 68.7% of the outstanding common stock of Jagged Peak. As all power and authority to control the core functions of Jagged Peak and JPE LLC were, and continue to be, controlled by Quantum, the corporate reorganization was treated as a reorganization of entities under common control and the results of JPE LLC have been consolidated and combined for all periods.

On January 27, 2017, the Company initiated its IPO of common stock to the public, and its common stock began trading on the New York Stock Exchange. During the IPO, the Company and selling stockholders sold 31,599,334 shares at $15.00 per share, raising $474.0 million of gross proceeds. Of the 31,599,334 shares issued to the public, 28,333,334 shares were sold by the Company, and 3,266,000 shares were sold by the selling stockholders. The gross proceeds of the IPO to the Company, based on the public offering price of $15.00 per share, were approximately $425.0 million, which resulted in net proceeds to the Company of $397.0 million after deducting expenses and underwriting discounts and commissions of approximately $28.0 million. The Company did not receive any proceeds from the sale of the shares by the selling stockholders. A portion of the proceeds from the IPO were used to repay the entire outstanding balance on JPE LLC’s credit facility of $142.0 million, as of the date the IPO proceeds were received. The remainder of the net proceeds from the IPO were used to fund a portion of the Company’s 2017 capital expenditures program, and for other general corporate purposes.

Basis of Presentation

The accompanying unaudited consolidated and combined financial statements include the accounts of Jagged Peak and JPE LLC, and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, and should be read in conjunction with the financial statements, summary of significant accounting policies and footnotes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as amended (the “2016 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 Company’s 2016 Form 10-K. All significant intercompany and intra-company 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

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

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 increases due to development activities, natural production declines, the uncertainty of exploration and development drilling results, the fair value of derivative instruments and other factors.

The unaudited consolidated and combined financial statements for periods prior to January 27, 2017 reflect the historical results of JPE LLC, other than the equity-based compensation expense and deferred tax expense, as further described in Notes 6 and 8, respectively.

Certain reclassifications have been made to prior period amounts to conform to the current presentation.

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 to the Company’s consolidated financial statements in its 2016 Form 10-K, and are supplemented by the notes to the consolidated and combined 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 and combined financial statements.

Use of Estimates

In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Estimates made in preparing these consolidated and combined financial statements include, among other things, (1) estimates relating to certain oil and natural gas revenue and costs, (2) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment calculations, (3) estimates of timing and costs used in calculating asset retirement obligations and impairment, (4) estimates used in developing fair value assumptions and estimates, and (5) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in the assumptions could have a significant impact on results in future periods.

Accounts Receivable

At September 30, 2017 and December 31, 2016, accounts receivable was comprised of the following:



(in thousands)	September 30, 2017		December 31, 2016
Oil and gas sales	$	22,946	$	8,861
Joint interest	10,769		580
Other	1,373		886
Total accounts receivable	$	35,088	$	10,327

At September 30, 2017 and December 31, 2016, the Company did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Oil and Natural Gas Properties

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



(in thousands)	September 30, 2017			December 31, 2016
Proved oil and natural gas properties	$	818,990		$	375,129
Unproved oil and natural gas properties	187,757			155,992
Total oil and natural gas properties	1,006,747			531,121
Less: Accumulated depletion	(123,448		)	(57,529		)
Total oil and natural gas properties, net	$	883,299		$	473,592

Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. For the three months ended September 30, 2017 and 2016, the Company recorded depletion for oil and natural gas properties of $30.4 million and $10.8 million, respectively. For the nine months ended September 30, 2017 and 2016, the Company recorded depletion for oil and natural gas properties of $65.9 million and $28.8 million, respectively.

Accrued Liabilities

The components of accrued liabilities are shown below:



(in thousands)	September 30, 2017		December 31, 2016
Accrued capital expenditures	$	86,433	$	28,490
Accrued accounts payable	3,349		3,312
Royalties payable	4,313		2,653
Other current liabilities	12,393		4,770
Total accrued liabilities	$	106,488	$	39,225

Equity-based Compensation

The Company recognizes compensation cost related to equity-based awards granted to employees, members of the Company’s board of directors and non-employee contractors in the financial statements based on their estimated grant-date fair value. The Company may grant various types of equity-based awards including stock options, stock appreciation rights, restricted stock, restricted stock units (including awards with service-based vesting and market condition-based vesting provisions), stock awards, dividend equivalents and other types of awards . Service-based restricted stock and units are valued using the market price of Jagged Peak’s common stock on the grant date. The fair value of the market condition-based restricted stock units are based on the grant-date fair value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period, and is recognized in general and administrative expense in the consolidated and combined statements of operations. The Company has elected to account for forfeitures in compensation expense as they occur. Equity-based compensation arrangements to nonemployees are recognized as expense over the related service period and are subject to remeasurement at the end of each reporting period until they vest.

Income Taxes

The Company is a subchapter C corporation and is subject to U.S. federal and state income taxes. Income taxes are accounted for under the asset and liability method. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which the Company operates for the year in which those temporary differences are expected to be recovered or settled. The Company classifies all deferred tax assets and liabilities as noncurrent. The Company recognizes the financial statement effects of a tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination. Net deferred tax assets are then reduced by a valuation allowance if the Company believes it is more likely than not such net deferred tax assets will not be realized.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new guidance will require a company to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-11, which rescinds the U.S. Securities and Exchange Commission (“SEC”) accounting guidance regarding the use of the entitlements method for recognition of natural gas revenues. The standards can be adopted using either a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09. The Company will adopt this standard on January 1, 2018, and will apply the modified retrospective method. The Company is in process of completing its evaluation of the impact of this standard on its financial statements and disclosures, internal controls and accounting policies. Based on the results to date, the Company has reached tentative conclusions and does not believe its existing revenue recognition processes and controls will change materially. The Company expects that certain additional disclosures will be required upon adoption of this standard.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires all leases with a term greater than one year to be recognized on the balance sheet as lease assets and lease liabilities. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. The new standard is effective for the Company on January 1, 2019. Although early adoption is permitted, the Company does not plan to early adopt the standard. The ASU requires the use of the modified retrospective approach, whereby lessees will be required to recognize and measure leases at the beginning of the earliest period presented. The Company is still in the process of evaluating the impact of this new standard; however, the Company believes the initial impact of adopting the standard will result in increases to its assets and liabilities on its consolidated balance sheets, and changes to the timing and presentation of certain operating expenses on its consolidated statements of operations.

In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting. The ASU clarifies which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The standard is effective for the Company on January 1, 2018, with early adoption permitted. The impact of this new standard will depend on the extent and nature of future changes to the terms of Company's equity-based payment awards.

Note 3—Derivative Instruments

The Company hedges a portion of its crude oil sales through derivative instruments to mitigate volatility in commodity prices. The use of these instruments exposes the Company to market basis differential risk if the WTI price does not move in parity with the Company’s underlying sales of crude oil produced in the Southern Delaware Basin. The Company also hedges a portion of its market basis differential risk through basis swap contracts.

The Company’s derivative instruments are carried at fair value on the consolidated and combined balance sheets. The Company estimates the fair value using risk adjusted discounted cash flow calculations. Cash flows are based on published future commodity price curves for the underlying commodity as of the date of the estimate. Due to the volatility of commodity prices, the estimated fair values of the Company’s derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. For more information, refer to Note 4, Fair Value Measurements.

As of September 30, 2017, the Company hedged commodity prices associated with a portion of its expected future oil volumes by entering into swap and basis swap derivative financial instruments. With swaps, the Company typically receives an agreed upon fixed price for a specified notional quantity of oil or natural gas, and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices. Basis swap contracts establish the differential between Cushing WTI prices and Midland WTI prices. The Company’s commodity derivatives may expose it to the risk of financial loss in certain circumstances. The Company’s derivative arrangements provide protection on the hedged volumes if market prices decline below the prices at which these derivatives are set. If market prices rise above the prices at which the Company has hedged, the Company will receive less revenue on the hedged volumes than it would receive in the absence of hedges.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

The following table summarizes the Company’s derivative contracts as of September 30, 2017:



Contract Period	Volumes (Bbls)	Wtd Avg Price ($/Bbl)
Oil Swaps⁽¹⁾:
Fourth quarter 2017	1,392,700	$	51.34
Year ending December 31, 2018	5,263,350	$	52.18
Year ending December 31, 2019	2,372,500	$	51.89
Oil Basis Swaps⁽²⁾:
Fourth quarter 2017	460,000	$	(1.00	)
Year ending December 31, 2018	5,110,000	$	(1.08	)
Year ending December 31, 2019	2,920,000	$	(1.10	)


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


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

The Company has elected to not apply hedge accounting, and as a result, its earnings are affected by the use of the mark-to-market method of accounting for derivative financial instruments. The changes in fair value of these instruments are recognized through earnings as other income or expense rather than deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity price indices. The ultimate gain or loss upon settlement of these transactions is recognized in earnings as other income or expense. Cash settlements of the Company’s derivative contracts are included in cash flows from operating activities in the Company’s statements of cash flows.

The Company recognized the following gains (losses) in earnings for the periods indicated:



	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2017			2016		2017			2016
Gain (loss) on derivatives instruments, net	$	(27,693	)	$	1,728	$	15,922		$	(8,208	)
Cash settlements of derivatives (received) paid, net	$	(3,195	)	$	337	$	(3,691	)	$	1,159

The Company’s derivative contracts are carried at their fair value on the Company’s consolidated and combined balance sheets using Level 2 inputs, and are subject to industry standard master netting arrangements, which allow the Company to offset recognized asset and liability fair value amounts on contracts with the same counterparty. The Company’s policy is to not offset these positions in its consolidated and combined balance sheets.

The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of September 30, 2017 and December 31, 2016 (in thousands):



As of September 30, 2017:	Balance Sheet Location	Gross amounts presented on the balance sheet		Netting adjustments not offset on the balance sheet			Net amounts
Assets
Commodity contracts	Current assets - derivative instruments	$	5,515	$	(5,361	)	$	154
Commodity contracts	Noncurrent assets - derivative instruments	5,170		(1,602		)	3,568
Total assets		$	10,685	$	(6,963	)	$	3,722
Liabilities
Commodity contracts	Current liabilities - derivative instruments	$	8,820	$	(5,361	)	$	3,459
Commodity contracts	Noncurrent liabilities - derivative instruments	2,490		(1,602		)	888
Total liabilities		$	11,310	$	(6,963	)	$	4,347

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Notes to Consolidated and Combined Financial Statements

(Unaudited)



As of December 31, 2016:	Balance Sheet Location	Gross amounts presented on the balance sheet		Netting adjustments not offset on the balance sheet		Net amounts
Liabilities
Commodity contracts	Current liabilities - derivative instruments	$	9,567	—		$	9,567
Commodity contracts	Noncurrent liabilities - derivative instruments	3,287		—		3,287
Total liabilities		$	12,854	$	—	$	12,854

Derivative Counterparty Risk

Where the Company is exposed to credit risk in its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, and monitors the appropriateness of these counterparties on an ongoing basis. Generally, the Company does not require collateral and does not anticipate nonperformance by its counterparties.

At September 30, 2017, the Company had commodity derivative contracts with three counterparties, all of which were lenders or affiliates of lenders under the Company’s Amended and Restated Credit Facility 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.

Note 4—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 proved oil and natural gas properties upon acquisition or impairment, are recognized at fair value on a nonrecurring basis.

The Company categorizes the inputs to the fair value of its financial assets and liabilities using a three-tier fair value hierarchy, established by the FASB, that prioritizes the significant inputs used in measuring fair value:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry standard models that consider various assumptions, including quoted prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in the category include nonexchange-traded derivatives such as over-the-counter forwards, swaps and options.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value, and the company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and liabilities measured on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. To determine the fair value at the end of each reporting period, the Company computes discounted cash flows for

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. The Company compares these prices to the price parameters contained in its hedge contracts to determine estimated future cash inflows or outflows, which are then discounted. The fair values of the Company’s commodity derivative assets and liabilities include a measure of credit risk. These valuations are Level 2 inputs.

The following table is a listing of the Company’s assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016:



	Level 2
(in thousands)	September 30, 2017		December 31, 2016
Assets from commodity derivative contracts	$	10,685	$	—
Liabilities due to commodity derivative contracts	$	11,310	$	12,854

Assets and liabilities measured on a nonrecurring basis

The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its nonfinancial assets and liabilities, such as the acquisition or impairment of proved and unproved oil and gas properties and the inception value of asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations.

The Company reviews its proved oil and natural gas properties for impairment whenever facts and circumstances indicate their carrying value may not be recoverable. In such circumstances, the income approach is used to determine the fair value of proved oil and natural gas reserves. Under this approach, the Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs. No impairments were recorded on proved properties during the three and nine months ended September 30, 2017 and 2016.

Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Company uses a market approach, and takes into account future development plans, remaining lease term, drilling results, and reservoir performance. The Company recorded impairment expense on unproved oil and gas properties of $0.3 million and $7,000 for the three months ended September 30, 2017 and 2016, respectively, and $0.4 million and $0.3 million for the nine months ended September 30, 2017 and 2016, respectively. These impairments resulted from the expirations of certain undeveloped leases.

The inception value and revision value, if any, 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 inflows and outflows. Given the unobservable nature of these inputs, they represent Level 3 inputs.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation approach based on inputs that are non-observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

Fair Value of Other Financial Instruments

The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, other current assets, accounts payable and accrued liabilities that approximate fair value due to the nature of the instrument and the short-term maturities of these instruments.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Note 5—Debt Obligations

In June 2015, JPE LLC entered into a five-year senior secured revolving credit facility (“JPE LLC’s Credit Facility”), with a maximum facility amount of $500.0 million. At December 31, 2016, JPE LLC’s Credit Facility, as amended, had a borrowing base of $160.0 million, with $132.0 million outstanding under the credit facility, and $28.0 million in unused borrowing capacity. The weighted-average interest rate as of December 31, 2016 was 3.99%. Following the IPO, the outstanding balance under JPE LLC’s credit facility was paid in full.

In January 2017, JPE LLC’s Credit Facility borrowing base was increased to $180.0 million, and the number of lenders was increased from five banks to nine banks.

In February 2017, the Company, as parent guarantor, and JPE LLC, as borrower, entered into an amended and restated credit facility with Wells Fargo Bank, N.A., as administrative agent and the lenders thereto (the “Amended and Restated Credit Facility”). The borrowing base and number of banks remained at $180.0 million and nine, respectively, while the maximum facility amount increased to $1.0 billion. Further, the Amended and Restated Credit Facility no longer contains the minimum hedging requirements that existed in JPE LLC’s credit facility. At September 30, 2017, borrowings under the Amended and Restated Credit Facility bore interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. At September 30, 2017, the applicable margin ranged from 1.25% to 2.25% in the case of the alternative base rate and from 2.25% to 3.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. At September 30, 2017, the Company paid a commitment fee of 0.50% per year on the unused portion of the borrowing base.

The Amended and Restated Credit Facility matures on February 1, 2022, and is subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year. The borrowing base increased from $180.0 million to $250.0 million after the April 2017 redetermination.

The Amended and Restated Credit Facility is secured by oil and natural gas properties representing at least 90% of the value of the Company’s proved reserves. The Amended and Restated Credit Facility contains certain covenants, including among others, restrictions on indebtedness, restrictions on liens, restrictions on investments, restrictions on mergers, restrictions on sales of assets, restrictions on dividends and payments to the Company’s capital interest holders and restrictions on the Company’s hedging activity.

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 agreement, include requirements to comply with the following financial ratios:

•

a current ratio, which is the ratio of consolidated current assets (including unused commitments under the credit facility and excluding noncash assets related to asset retirement obligations and derivatives) to consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and noncash liabilities related to asset retirement obligations and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and


•	a leverage ratio, which is the ratio of consolidated Debt (as defined in the credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in the credit agreement) to EBITDAX (as defined in the credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0.

As of September 30, 2017, the Company was in compliance with its financial covenants.

As of September 30, 2017, there was $35.0 million outstanding balance under the Amended and Restated Credit Facility. The weighted-average interest rate as of September 30, 2017 was 3.49%.

In October 2017, the Company and JPE LLC entered into an amendment to the Amended and Restated Credit Facility (“Amendment No. 1”). Under Amendment No. 1, the borrowing base increased to $425.0 million and the pricing grid was lowered, while the number of banks providing commitments remained at nine. Following Amendment No. 1, the Amended and

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Restated Credit Facility remains subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year, with the next scheduled redetermination on or around April 1, 2018. Borrowings under the Amended and Restated Credit Facility following Amendment No. 1 bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate, and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company pays a commitment fee of 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.

Note 6—Equity-based Compensation

In connection with the IPO, the Company adopted the Jagged Peak Energy Inc. 2017 Long Term Incentive Plan (the “Plan”), which allows the Company to grant up to 21,200,000 equity-based compensation shares to employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, performance awards and other types of awards. The terms and conditions of the awards granted are established by the Company’s Board of Directors.

Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated and combined statements of operations, was as follows for the periods indicated:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2017		2016		2017		2016
Incentive unit awards	$	10,692	$	—	$	429,585	$	—
Restricted stock unit awards	521		—		898		—
Performance stock unit awards	527		—		866		—
Restricted stock unit awards issued to nonemployee directors	163		—		293		—
Total equity-based compensation expense	$	11,903	$	—	$	431,642	$	—

Incentive Unit Awards

In connection with its formation in April 2013, JPE LLC established an incentive pool plan, whereby JPE LLC granted MIUs to employees and selected other participants. The MIUs were considered “profits interests” that participated in certain events whereupon distributions would be made to MIU holders (only after certain return thresholds were achieved by the capital interests) following a qualifying initial public offering, sale, merger, or other qualifying transaction involving the units or assets of JPE LLC (“Vesting Event”).

The MIUs were accounted for under FASB ASC Topic 710, Compensation–General, which requires compensation expense for the MIUs to be recognized when all performance, market and service conditions are probable of being satisfied, which is generally upon a Vesting Event. As of and through December 31, 2016, the vesting of the MIUs was not deemed probable, therefore no expense was recognized through December 31, 2016.

The corporate reorganization provided a mechanism by which all capital interests and MIUs in JPE LLC were converted into a single class of units, which were then converted into the Company’s common stock. A portion of these shares vested and a portion were transferred to JPE Management Holdings LLC (“Management Holdco”) and became subject to the terms and conditions of the amended and restated JPE Management Holdings LLC limited liability company agreement (the “Management Holdco LLC Agreement”). As a result of the IPO, the satisfaction of all conditions relating to MIUs in JPE LLC held by the current and former officers and employees who owned equity interests in JPE LLC, was deemed probable. As a result, based on the Company’s IPO price of $15.00 per share, compensation expense of $379.0 million was recognized for the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016.

The shares of common stock transferred to Management Holdco are accounted for under ASC 718, Compensation–Stock Compensation, and generally vest over three years. During the three and nine months ended September 30, 2017, the Company

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

recognized $10.7 million and $50.6 million, respectively, of equity-based compensation expense related to the shares held by Management Holdco. Included in the $50.6 million for the nine months ended September 30, 2017, is $22.2 million of equity-based compensation related to awards held by Management Holdco which were modified in conjunction with a March 2017 separation agreement of a former executive officer. The remaining compensation expense of these awards will be recognized ratably according to the terms of the Management Holdco LLC Agreement.

A summary of incentive unit award activity for the nine months ended September 30, 2017 is as follows:



				Weighted Average
				Grant-date
	Incentive Units			Fair Value
Unvested at Corporate Reorganization	9,570,280			$	15.00
Granted	235,346			$	12.41
Vested	(2,049,881		)	$	14.97
Forfeited	—			$	—
Unvested at September 30, 2017	7,755,745			$	14.93
Compensation costs remaining at September 30, 2017 (in millions)	$	90.5
Weighted average remaining period at September 30, 2017 (in years)	2.3

The total fair value of incentive units that vested during the nine months ended September 30, 2017 was $25.2 million.

At September 30, 2017, there were 431,321 of unallocated shares of Company common stock held at Management Holdco which, when granted, will be valued using the closing stock price on the date of grant, and the Company will recognize expense over the requisite service period.

Restricted Stock Unit Awards

Restricted stock unit awards (“RSUs”) vest subject to the satisfaction of service requirements. Expense related to each RSU award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur through reversal of expense on awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant.

A summary of RSU award activity for the nine months ended September 30, 2017 is as follows:



				Weighted Average
				Grant-date
	RSUs			Fair Value
Unvested at December 31, 2016	—			$	—
Granted	576,264			$	12.42
Vested	—			$	—
Forfeited	(5,921		)	$	12.61
Unvested at September 30, 2017	570,343			$	12.42
Compensation costs remaining at September 30, 2017 (in millions)	$	5.9
Weighted average remaining period at September 30, 2017 (in years)	2.4

Of the 576,264 RSUs granted during the nine months ended September 30, 2017, nonemployee directors received 55,744 at a weighted average grant-date fair value of $12.46. The remaining compensation costs at September 30, 2017 for these nonemployee director RSUs was $0.4 million, with a weighted average remaining period of 0.6 years.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Performance Stock Unit Awards

During the nine months ended September 30, 2017, the Company granted performance stock unit awards (“PSUs”) to certain of its executive officers, which vest based on continuous employment and satisfaction of a performance metric based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR of a peer group of companies over an approximate three-year performance period ending December 31, 2019. The number of shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over approximately three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.

A summary of PSU award activity for the nine months ended September 30, 2017 is as follows:



			Weighted Average
			Grant-date
	PSUs		Fair Value
Unvested at December 31, 2016	—		$	—
Granted	398,566		$	16.32
Vested	—		$	—
Forfeited	—		$	—
Unvested at September 30, 2017	398,566		$	16.32
Compensation costs remaining at September 30, 2017 (in millions)	$	5.6
Weighted average remaining period at September 30, 2017 (in years)	2.3

The grant-date fair value of the PSUs was determined using a Monte Carlo simulation, which uses a probabilistic approach for estimating the fair value of the awards. The expected volatility was derived from a weighted combination of implied volatility and historical volatility. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs.

The following table presents information regarding the weighted average fair value for PSUs granted during the nine months ended September 30, 2017 and the assumptions used to determine the fair values:



	Nine Months Ended
	September 30, 2017
Dividend yield	—		%
Volatility	55.7		%
Risk-free interest rate	1.34		%
Weighted average fair value of awards granted	$	16.32

Note 7—Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net earnings by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested RSUs and PSUs, if including such potential shares of common stock units is dilutive. The PSUs included in the calculation of diluted weighted average shares outstanding based on the number of shares of common stock that would be issuable if the end of the reporting period was the end of the performance period required for the vesting of such PSU awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all awards is anti-dilutive.

For the nine months ended September 30, 2017, the Company’s EPS calculation includes only the net loss for the period subsequent to the corporate reorganization and IPO, and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017, to September 30, 2017.

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Notes to Consolidated and Combined Financial Statements

(Unaudited)

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



	Three Months Ended			From January 27, 2017, to
(in thousands, except per share amounts)	September 30, 2017			September 30, 2017
Net income (loss) attributable to Jagged Peak Energy Inc. stockholders	$	(15,219	)	$	(89,221	)

Basic weighted average shares outstanding	212,931			212,933
Effect of dilutive securities:
Restricted stock units	—			—
Performance stock units	—			—
Diluted weighted average shares outstanding	212,931			212,933

Net income (loss) per common share:
Basic	$	(0.07	)	$	(0.42	)
Diluted	$	(0.07	)	$	(0.42	)

The following table presents amounts that have been excluded from the computation of diluted earnings per common share as their inclusion would be anti-dilutive:



	Three Months Ended	From January 27, 2017, to
(in thousands)	September 30, 2017	September 30, 2017
Weighted average number of outstanding equity awards excluded from diluted earnings per share calculation:⁽¹⁾
Restricted stock units	527	348
Performance stock units	671	421


(1)	When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be anti-dilutive.

Note 8—Income Taxes

JPE LLC was organized as a limited liability company and treated as a pass-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of the Company from January 27, 2017 through September 30, 2017 in the accompanying consolidated and combined financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the change in tax status as a result of the corporate reorganization, the Company established a $79.1 million provision for deferred income taxes, which was recognized as tax expense from continuing operations in the first quarter of 2017.

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The components of the Company’s provision for income taxes are as follows:



	Three Months Ended			Nine Months Ended
(in thousands)	September 30, 2017			September 30, 2017
Current income tax expense:
Federal	$	—		$	—
State	—			—
	—			—
Deferred income tax expense:
Federal	(2,543		)	98,904
State	(55		)	2,135
	(2,598		)	101,039
Provision for income taxes	$	(2,598	)	$	101,039

Included in the deferred federal income tax provision above for the nine months ended September 30, 2017, is the $79.1 million related to the Company’s change in tax status.

A reconciliation of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense is as follows:



	Three Months Ended			Nine Months Ended
(in thousands)	September 30, 2017			September 30, 2017
Income (loss) before income taxes	$	(17,817	)	$	(363,658	)
Less: net loss prior to corporate reorganization	—			(375,476		)
Income (loss) before income taxes subsequent to corporate reorganization	$	(17,817	)	$	11,818

Income taxes at the federal statutory rate	$	(6,236	)	$	4,136
Income tax expense relating to change in tax status	—			78,019
State income taxes, net of federal benefit	(35		)	1,388
Nondeductible equity-based compensation	3,671			17,479
Other permanent differences	2			17
Income tax expense (benefit)	$	(2,598	)	$	101,039
Effective tax rate	14.6		%	(27.8		)%

Prior to the Company’s change in tax status in January 2017, income taxes did not significantly impact the results of operations.

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The components of the Company’s deferred income tax assets and liabilities as of September 30, 2017 are as follows:



(in thousands)	September 30, 2017
Deferred income tax assets:
Net operating loss carryforwards	$	1,526
Commodity derivatives	221
Equity-based compensation	502
Other	1,302
	3,551
Deferred income tax liabilities:
Oil and natural gas properties	104,590
	104,590
Net deferred income tax assets (liabilities)	$	(101,039	)

The Company had U.S. net operating losses of approximately $4.3 million, which expire in 2036. Deferred tax assets are reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized. At September 30, 2017, the Company did not have a valuation allowance.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. At September 30, 2017, the Company had no unrecognized tax benefits that would impact the effective tax rate and has made no provisions for interest or penalties related to uncertain tax positions.

The Company files income tax returns in the U.S. federal jurisdiction, Texas and Colorado. There are currently no federal or state income tax examinations underway. The Company’s U.S. federal income tax returns remain open to examination by the taxing authorities for tax years 2014 through 2017, and its Texas and Colorado tax returns remain open to examination for the years 2013 through 2016 and 2013 through 2017, respectively.

Note 9—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, 2017:



(in thousands)
Asset retirement obligations at January 1, 2017	$	448
Liabilities incurred and assumed	492
Liability settlements and disposals	(10		)
Revisions of estimated liabilities	(5		)
Accretion	49
Asset retirement obligations at September 30, 2017	974
Less current portion of asset retirement obligations	(284		)
Long-term asset retirement obligations	$	690

The current portion of the asset retirement obligation liability is included in accrued liabilities on the consolidated and combined balance sheets.

Note 10—Commitments and Contingencies

Commitments

There were no material changes in commitments during the first nine months of 2017, except as discussed below. Please refer to Note 9, Commitments and Contingencies, in the 2016 Form 10-K for additional discussion.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

At September 30, 2017, the Company had seven drilling rigs under contract. If the Company were to terminate these contracts at September 30, 2017, it would be required to pay early termination penalties of $11.1 million. In the first nine months of 2016, the Company terminated one drilling rig and incurred early termination charges of approximately $0.2 million. These charges are reflected as other operating costs in the consolidated and combined statements of operations.

At September 30, 2017, the Company had three frac fleets under contract through December 31, 2018. The remaining commitment at September 30, 2017 for these contracts is $13.8 million in 2017, and $73.2 million in 2018. The majority of the contracts allow for reassignment of the frac fleets if the Company were to terminate their services prior to the end of the contract, at which point the Company would not be required to pay termination fees. However, if the fleets were not able to be reassigned, the Company would be required to pay termination fees of $66.2 million as of September 30, 2017.

During the second quarter of 2017, the Company entered into a lease agreement of its new corporate offices, which is expected to take effect in December 2017 and expire in May 2028. Including this new lease agreement, the Company has commitments for office space and equipment under operating lease arrangements totaling $16.7 million.

Contingencies

Legal Matters

In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental Matters

The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.

Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both September 30, 2017 and December 31, 2016, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Note 11—Related Party Transactions

Quantum employs certain members of the Company’s board of directors and had significant capital interests in JPE LLC. After giving effect to the IPO, Quantum owns 68.7% of the Company’s common stock.

Quantum owns a 41.5% interest in Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”). The Company has a 12-year crude oil gathering agreement with Oryx whereby Oryx provides midstream gathering services to the Company. Under that agreement, the Company has the right to designate, and has designated, a third-party shipper to market the Company’s crude oil. In addition, the Company paid fees to Oryx for the purchase and maintenance of connecting equipment.

Quantum also owns a 60.9% interest in Phoenix Lease Services, LLC (“Phoenix”), and an indirect interest in Trident Water Services, LLC (“Trident”), a wholly owned subsidiary of Phoenix. The Company regularly leases frac tanks and other oil field equipment from Phoenix, and regularly uses water transfer services provided by Trident. The Company is under no obligation to use either provider, and both provide services only when selected as a vendor through the Company’s normal bidding process.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2017		2016		2017		2016
Oryx via 3rd party shipper⁽¹⁾	$	2,918	$	938	$	6,716	$	1,037
Oryx⁽²⁾	$	97	$	166	$	749	$	1,091
Phoenix	$	56	$	111	$	258	$	260
Trident	$	—	$	90	$	236	$	413


(1)	Transportation fees paid by the Company’s third party shipper to Oryx pursuant to the crude oil gathering agreement.


(2)	Fees paid to Oryx for the purchase and maintenance of connecting equipment.

At September 30, 2017 and December 31, 2016, the Company had outstanding payables to these related parties of $1.1 million and $0.7 million, respectively.


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 and combined financial statements and related notes presented in this Quarterly Report on Form 10-Q as well as our audited consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2016, as amended. The following 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” elsewhere in this Quarterly Report on Form 10-Q and “Part 1, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016.

In this section, references to “Jagged Peak,” “the Company,” “we,” “us” and “our” refer to Jagged Peak Energy Inc. and its subsidiaries, after the initial public offering of Jagged Peak (the “IPO”) and, prior to the IPO, to Jagged Peak Energy LLC (“JPE LLC”).

Jagged Peak Energy Inc. and our Predecessor

Jagged Peak was formed in September 2016 and, prior to the consummation of the IPO, did not have historical financial operating results. For purposes of this Quarterly Report, our accounting predecessor reflects the results of JPE LLC, which was formed in 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Southern Delaware Basin of the Permian Basin. In connection with the IPO, a corporate reorganization took place whereby JPE LLC became a wholly owned subsidiary of Jagged Peak.

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, a sub-basin of the Permian Basin and one of the most prolific unconventional resource plays in North America. 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.

We have assembled a portfolio of contiguous acreage in the core oil window of the Southern Delaware Basin. This acreage is characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that provide attractive growth and return opportunities. At September 30, 2017, our acreage position was approximately 72,600 net acres. We divide our current areas of operation into three distinct areas: (1) Cochise, with approximately 12,900 net acres, (2) Whiskey River, with approximately 35,700 net acres, and (3) Big Tex, with approximately 24,000 net acres.

We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As the operator of approximately 97% of our acreage, we have the flexibility to manage our development program, which allows us to optimize our field-level returns and profitability.

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Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. Compared to the first nine months of 2016, our realized oil price for the first nine months of 2017 increased 18% to $46.06 per barrel, our realized natural gas price improved 18% to $2.56 per Mcf, and our realized price for NGLs improved by 55% to $22.28 per barrel between the same periods. See “Sources of Our Revenues” below for further information regarding our realized commodity prices.

Factors Affecting the Comparability of Our Results of Operations

Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, primarily for the reasons described below.

Incentive Unit Awards

Related to the closing of the IPO, we recognized equity-based compensation expense for: (1) a charge of $379.0 million related to MIUs in JPE LLC that vested at the time of the IPO; and (2) a charge for the nine months ended September 30, 2017 of $50.6 million related to shares of common stock transferred to Management Holdco. Please refer to Note 6, Equity-based Compensation, for additional information on equity-based compensation.

Public Company Expenses

As a result of the IPO, we incur direct, incremental general and administrative (“G&A”) expenses as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, corporate tax return preparation, increased independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental G&A expenses are not included in the predecessor’s historical results of operations.

Income Taxes

As a result of our corporate reorganization, we became subject to federal and state income tax. The change in tax status required the recognition of deferred tax assets and liabilities for the temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $79.1 million was recognized as tax expense from continuing operations. For periods following completion of the corporate reorganization, we began recording income taxes associated with our status as a corporation. From the date of the corporate reorganization through September 30, 2017, we recognized $21.9 million of income tax expense. Please refer to Note 8, Income Taxes, for more information on income taxes.

Increased Drilling Activity

Since commencing our drilling program in late 2013, we operated an average of one horizontal drilling rig through June 2016. We began operating our second and third rigs in July of 2016. At September 30, 2017, we were operating seven horizontal rigs. During the remainder of 2017, we expect to operate an average of six-drilling rigs and three fracturing fleets. During the nine months ended September 30, 2017, we completed 32 gross (30.9 net) operated wells. Our average daily production has grown from 5,336 Boe/d during the first nine months of 2016 to 14,594 Boe/d for the same period of 2017. In the nine months ended September 30, 2017, we spent $420.9 million for drilling and completing wells and on water infrastructure costs, which includes $1.2 million to purchase surface acreage. This compares to $90.0 million that we spent in the nine months ended September 30, 2016, and $158.3 million that we spent in all of 2016 for drilling and completion.

Summary of Operating and Financial Results Comparing the Nine Months Ended September 30, 2017 and 2016


•	Successfully completed, or participated in completing, 37 gross (32.8 net) wells, of which we operated 32 gross (30.9 net), all within the Southern Delaware Basin;


•	Increased average daily production by 174% to 14,594 Boe/d, comprised of 81% oil;


•	Production revenues rose 221% to $162.5 million;


•	Improved cash flow from operating activities to $105.4 million from $16.8 million for the same period of 2016;


•	Recorded a $15.9 million gain on commodity derivative instruments compared to a $8.2 million loss from the same period in 2016; and


•	Incurred equity-based compensation expense of $431.6 million, all of which was noncash except for $14.7 million related to an advance made in April 2016.

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•	Successfully delineated three new zones on our acreage—the 2^nd Bone Spring, Wolfcamp C and Woodford Shale—adding additional reserves and drilling locations to our acreage position.

In addition, in October 2017, we completed our most recent borrowing base redetermination, which resulted in an increase to the borrowing base from $250.0 million to $425.0 million.

Sources of Our Revenues

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. For the nine months ended September 30, 2017, our production revenues were derived 91% from oil sales, 3% from natural gas sales and 6% from NGL sales. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

Increases or decreases in our revenue, profitability and future production growth 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, seasonality and geopolitical and economic factors.

The following table presents our average realized commodity prices, the effects of derivative settlements on our realized prices, and certain major U.S. index prices.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Crude Oil (per Bbl):
Average NYMEX price	$	48.18	$	44.85	$	49.30	$	41.35
Realized price, before the effects of derivative settlements	$	45.24	$	42.03	$	46.06	$	39.03
Realized price, after the effects of derivative settlements	$	47.55	$	41.34	$	47.21	$	38.07
Natural Gas (per Mcf):
Average NYMEX price	$	2.95	$	2.88	$	3.01	$	2.34
Realized price	$	2.59	$	2.59	$	2.56	$	2.17
NGLs (per Bbl):
Average realized NGL price	$	25.31	$	14.89	$	22.28	$	14.35

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials for these products.

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

In addition to sales of oil, natural gas, and NGLs, we derive a minimal portion of our revenues from third party sales of fresh water and produced water disposal services. These revenues are reflected as other operating revenues in the consolidated and combined statements of operations.

Production Results

The following table presents production volumes for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Oil (MBbls)	1,383	484	3,208	1,210
Natural gas (MMcf)	1,136	282	2,224	669
NGLs (MBbls)	192	55	406	141
Total (MBoe)	1,765	586	3,984	1,462
Average net daily production (Boe/d)	19,180	6,366	14,594	5,336

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Production Volumes Directly Impact Our Results of Operations

As reservoir pressures decline, production from a given well or formation decreases. Growth in our cash flow, future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through drilling, as well as acquisitions. Our ability to add reserves through drilling projects and acquisitions is dependent on many factors, including our ability to increase our levels of cash flow from operations, borrow or raise capital, obtain regulatory approvals, procure materials, services and personnel and successfully identify and consummate acquisitions.

Derivative Activity

Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. As of September 30, 2017, we had entered into derivative oil swap contracts covering periods from October 1, 2017 through December 31, 2019 for approximately 9.0 MMbls of our projected oil production at a weighted average WTI oil price of $51.97 per barrel. We also have basis differential contracts between Midland, TX and Cushing, OK for the periods from October 1, 2017 through December 31, 2019 covering 8.5 MMbls at a weighted average basis differential of $(1.08) per barrel. These derivative instruments allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. This will provide increased certainty of cash flows for funding our drilling program and debt service requirements. 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 seek to hedge price risk associated with our natural gas and NGL production. See “Item 3—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

Results of Operations

Comparison of the three months ended September 30, 2017 versus September 30, 2016

Oil and Natural Gas Revenues. The following table provides the components of our production revenues for the three months ended September 30, 2017 and 2016, as well as each period’s respective average prices and production volumes:



	Three Months Ended September 30,
(in thousands or as indicated)	2017		2016		Change		% Change
Production Revenues:
Oil sales	$	62,585	$	20,332	$	42,253	208	%
Natural gas sales	2,939		731		2,208		302	%
NGL sales	4,860		819		4,041		493	%
Total production revenues	$	70,384	$	21,882	$	48,502	222	%
Average sales price⁽¹⁾:
Oil (per Bbl)	$	45.24	$	42.03	$	3.21	8	%
Natural gas (per Mcf)	$	2.59	$	2.59	$	—	—	%
NGLs (per Bbl)	$	25.31	$	14.89	$	10.42	70	%
Total (per Boe)	$	39.89	$	37.36	$	2.53	7	%
Production volumes:
Oil (MBbls)	1,383		484		899		186	%
Natural gas (MMcf)	1,136		282		854		303	%
NGLs (MBbls)	192		55		137		249	%
Total (MBoe)	1,765		586		1,179		201	%
Average daily production volume:
Oil (Bbls/d)	15,036		5,258		9,778		186	%
Natural gas (Mcf/d)	12,346		3,061		9,285		303	%
NGLs (Bbls/d)	2,087		598		1,489		249	%
Total (Boe/d)	19,180		6,366		12,814		201	%


(1)	Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.

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As reflected in the table above, our total production revenue for the three months ended September 30, 2017 was 222%, or $48.5 million, higher than that of the same period from 2016. The increase is primarily due to higher sales volumes, along with higher realized commodity prices during the three months ended September 30, 2017. Our aggregate production volumes in the three months ended September 30, 2017 were 1,765 MBoe, comprised of 78% oil, 11% natural gas and 11% NGLs. This represents an increase of 201% over the aggregate production volumes from the three months ended September 30, 2016, of 586 MBoe.

Increased production volumes accounted for an approximate $42.1 million increase in quarter-over-quarter production revenues, while increases in our total average sales prices accounted for an approximate $6.4 million increase in production revenues for the same period. Production increases are largely related to our active drilling program over the last 12 months.

During the three months ended September 30, 2017, oil revenues increased 208%, or $42.3 million, due to a 186% increase in production volumes and an 8% increase in the average realized price when compared to the same period from the prior year. Natural gas revenues increased 302% to $2.9 million during the three months ended September 30, 2017 from $0.7 million during the three months ended September 30, 2016. The increase is attributable to a 303% increase in volumes, while the average sales price was flat between periods. During the three months ended September 30, 2017, NGL revenues increased 493%, or $4.0 million, due to a 249% increase in sales volumes and a 70% increase in the average realized price.

Other operating revenues relate to sales of fresh water and water disposal services to third parties. During the three months ended September 30, 2017 and 2016, we recognized other operating revenues of $0.1 million and $0.2 million, respectively.

Operating Expenses. We present per-Boe information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis.

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



	Three Months Ended September 30,									Per Boe
(in thousands, except per Boe)	2017		2016		Change			% Change		2017		2016
Lease operating expenses	$	5,184	$	2,285	$	2,899		127	%	$	2.94	$	3.90
Gathering and transportation expenses	1,357		294		1,063			362	%	$	0.77	$	0.50
Production and ad valorem taxes	4,739		1,341		3,398			253	%	$	2.69	$	2.29
Exploration	6		—		6			NM		$	—	$	—
Depletion, depreciation, amortization and accretion	30,851		11,152		19,699			177	%	$	17.48	$	19.04
Impairment of unproved oil and natural gas properties	257		7		250			3,571	%	NM		NM
Other operating expenses	41		169		(128		)	(76	)%	$	0.02	$	0.29
General and administrative (before equity-based compensation)	5,830		2,375		3,455			145	%	$	3.30	$	4.06
Total operating expenses (before equity-based compensation)	48,265		17,623		30,642			174	%	$	27.35	$	30.09
Equity-based compensation	11,903		—		11,903
Total operating expenses	$	60,168	$	17,623	$	42,545

NM—Not meaningful.

Lease Operating Expenses. Our lease operating expense (“LOE”) varies in conjunction with our level of production, the timing of our workover expenses and variations in industry activity that cause fluctuations in service provider costs. LOE increased to $5.2 million in the three months ended September 30, 2017, compared to $2.3 million for the same period of 2016. The increase in LOE is generally associated with our increased level of production and well counts between periods, including costs for contract labor, equipment repair and maintenance, chemicals and electricity. Additionally, the three months ended September 30, 2017 saw an increase in workovers over the same period of the prior year which contributed to the increase. LOE per Boe decreased 25% between periods to $2.94 for the three months ended September 30, 2017, primarily because the increase in production between those two periods largely came from the addition of high-producing, low-operating cost wells.

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Gathering and Transportation Expenses. Gathering and transportation expenses increased $1.1 million during the three months ended September 30, 2017, compared to the same period of 2016, primarily due to increased production over the same period. In addition, we experienced an increase in our per unit gathering and transportation expense. The period over period increase in our per unit gathering and transportation expense is due to a shift away from marketing our natural gas under percent-of-proceeds contracts toward marketing a larger portion of our natural gas under fixed fee contracts. Under percent-of-proceeds contracts, we receive a percentage of the total proceeds received by the marketer, which is net of gathering and transportation costs. Conversely, under our fixed fee natural gas marketing contracts, our gas and NGL sales revenue is determined after transporting gas to a downstream sales point and we are separately charged for the associated gathering, transportation and processing costs.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 253% between the three months ended September 30, 2017 and 2016, from $1.3 million in 2016 to $4.7 million in 2017. The increase in production taxes is due to an increase in revenues, and the increase in ad valorem taxes is primarily due to the addition of multiple new high-volume wells.

Exploration. During the three months ended September 30, 2017, the Company recorded exploration expense of $6,000 due to delay rentals, compared to no exploration expenses for the same period of 2016.

Depletion, Depreciation, Amortization and Accretion. Depletion, depreciation, amortization and accretion (“DD&A”) expense increased $19.7 million, or 177%, during the three months ended September 30, 2017 compared to the same period of 2016. The increase in DD&A expense was largely due to an increase in production, partially offset by a decrease in our DD&A rate. Our DD&A rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The DD&A rate per Boe decreased 8% to $17.48 per Boe, compared to $19.04 per Boe in the three months ended September 30, 2016. The decrease in our DD&A rate was largely due to an increase in reserve volumes due to continued successful drilling activities, partly offset by an increase in capitalized costs in proved property related to those drilling activities.

Impairment of Unproved Oil and Natural Gas Properties. During the three months ended September 30, 2017 and 2016, we incurred $0.3 million and $7,000, respectively, of impairment costs related to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties in either period of 2017 or 2016.

Other Operating Expenses. Other operating expenses decreased $0.1 million for the three months ended September 30, 2017 compared to the same period of 2016. We incurred $41,000 of other operating expenses in the three months ended September 30, 2017, primarily due to sales of fresh water and water disposal to third parties. During the same period of 2016, we incurred other operating expenses of $0.2 million due to sales of fresh water and water disposal to third parties.

General and Administrative and equity-based compensation. G&A (excluding equity-based compensation) increased 145% to $5.8 million for the three months ended September 30, 2017, from $2.4 million for the same period of 2016. The increase is primarily due to a $3.0 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the growth of our capital expenditure program and production levels. The number of our full-time employees grew from 30 at September 30, 2016 to 56 at September 30, 2017.

Equity-based compensation expense for the three months ended September 30, 2017 was $11.9 million, of which $10.7 million related to the common stock transferred to Management Holdco, which is subject to the terms of the Management Holdco LLC Agreement. Also included in the $11.9 million is equity-based compensation expense for RSUs and PSUs of $0.7 million and $0.5 million, respectively. Please refer to Note 6, Equity-based Compensation, for additional information on equity-based compensation.

Other Income and Expense. The following table summarizes our other income and expenses for the periods indicated:



	Three Months Ended September 30,
(in thousands)	2017			2016			Change
Gain (loss) on commodity derivatives	$	(27,693	)	$	1,728		$	(29,421	)
Interest expense, net	(467		)	(759		)	292
Other, net	60			—			60
Total other income (expense)	$	(28,100	)	$	969		$	(29,069	)

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of the instruments. As a result, settlements on the contracts are included as a component of other income and expense as either a net gain or loss on derivative instruments. To the extent the future commodity price outlook declines between measurement periods, we will have noncash mark-to-market gains during the period. Conversely, to the extent future commodity price outlook increases between measurement periods, we will have noncash mark-to-market losses during the period.

The following table sets forth the net gain (loss) from settlements and changes in the fair value of our derivative contracts, as well as the net cash settlements (received) paid for the three months ended September 30, 2017 and 2016:



	Three Months Ended September 30,
(in thousands)	2017			2016
Gain (loss) on derivatives instruments, net	$	(27,693	)	$	1,728
Cash settlements of derivatives (received) paid, net	$	(3,195	)	$	337

Interest Expense, net. Interest expense relates to interest paid on the outstanding balance of the credit facility, commitment fees paid on the unused borrowing base and amortization of debt issuance costs, net of capitalized interest. During the three months ended September 30, 2017 and 2016, we recorded $0.5 million and $0.8 million, respectively, of interest expense, net of capitalized interest, related to borrowings on our credit facility. The decrease in interest expense from the three months ended September 30, 2016 to the same period of 2017 primarily relates to a decrease in borrowings during 2017. Average outstanding borrowings during the three months ended September 30, 2017 were $11.7 million, compared to $80.0 million during the same period from the prior year. This was partially offset by increased commitment fees due to a higher borrowing base, and higher amortization of debt issuance costs related to additional financing costs incurred throughout 2016 and the first part of 2017 related to amendments to the credit agreement and borrowing base increases.

Comparison of the nine months ended September 30, 2017 versus September 30, 2016

Oil and Natural Gas Revenues. The following table provides the components of our production revenues for the nine months ended September 30, 2017 and 2016, as well as each period’s respective average prices and production volumes:



	Nine Months Ended September 30,
(in thousands or as indicated)	2017		2016		Change		% Change
Production Revenues:
Oil sales	$	147,738	$	47,215	$	100,523	213	%
Natural gas sales	5,697		1,450		4,247		293	%
NGL sales	9,041		2,023		7,018		347	%
Total production revenues	$	162,476	$	50,688	$	111,788	221	%
Average sales price⁽¹⁾:
Oil (per Bbl)	$	46.06	$	39.03	$	7.03	18	%
Natural gas (per Mcf)	$	2.56	$	2.17	$	0.39	18	%
NGLs (per Bbl)	$	22.28	$	14.35	$	7.93	55	%
Total (per Boe)	$	40.78	$	34.67	$	6.11	18	%
Production volumes:
Oil (MBbls)	3,208		1,210		1,998		165	%
Natural gas (MMcf)	2,224		669		1,555		232	%
NGLs (MBbls)	406		141		265		188	%
Total (MBoe)	3,984		1,462		2,522		173	%
Average daily production volume:
Oil (Bbls/d)	11,750		4,415		7,335		166	%
Natural gas (Mcf/d)	8,147		2,443		5,704		233	%
NGLs (Bbls/d)	1,486		514		972		189	%
Total (Boe/d)	14,594		5,336		9,258		174	%


(1)	Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.

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As reflected in the table above, our total production revenue for the first nine months of 2017 was 221%, or $111.8 million, higher than that of the same period from 2016. The increase is primarily due to higher sales volumes, along with higher realized commodity prices during the first nine months of 2017. Our aggregate production volumes in the first nine months of 2017 were 3,984 MBoe, comprised of 81% oil, 9% natural gas and 10% NGLs. This represents an increase of 173% over the first nine months of 2016 aggregate production volumes of 1,462 MBoe.

Increased production volumes accounted for an approximate $85.2 million increase in year-over-year production revenues, while increases in our total average sales prices accounted for an approximate $26.6 million increase in production revenues for the same period. Production increases are largely related to our active drilling program over the last 12 months.

During the nine months ended September 30, 2017, oil revenues increased 213%, or $100.5 million, due to a 165% increase in production volumes and an 18% increase in the average realized price when compared to the same period from the prior year. Natural gas revenues increased 293% to $5.7 million during the nine months ended September 30, 2017 from $1.5 million during the nine months ended September 30, 2016. The increase is attributable to a 232% increase in volumes and an 18% increase in the average sales price. During the first nine months of 2017, NGL revenues increased 347%, or $7.0 million, due to a 188% increase in volumes and a 55% increase in the average realized price.

Other operating revenues relate to sales of fresh water and water disposal services to third parties. During the first nine months of 2017 and 2016, we recognized other operating revenues of $0.4 million and $1.0 million, respectively.

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



	Nine Months Ended September 30,									Per Boe
(in thousands, except per Boe)	2017		2016		Change			% Change		2017		2016
Lease operating expenses	$	10,684	$	5,254	$	5,430		103	%	$	2.68	$	3.59
Gathering and transportation expenses	2,404		662		1,742			263	%	$	0.60	$	0.45
Production and ad valorem taxes	10,916		3,173		7,743			244	%	$	2.74	$	2.17
Exploration	14		2,474		(2,460		)	(99	)%	$	—	$	1.69
Depletion, depreciation, amortization and accretion	67,224		29,430		37,794			128	%	$	16.87	$	20.13
Impairment of unproved oil and natural gas properties	365		317		48			15	%	NM		NM
Other operating expenses	223		567		(344		)	(61	)%	$	0.06	$	0.39
General and administrative (before equity-based compensation)	17,862		7,878		9,984			127	%	$	4.48	$	5.39
Total operating expenses (before equity-based compensation)	109,692		49,755		59,937			120	%	$	27.53	$	34.03
Equity-based compensation	431,642		—		431,642
Total operating expenses	$	541,334	$	49,755	$	491,579

NM—Not meaningful.

Lease Operating Expenses. Our LOE varies in conjunction with our level of production, the timing of our workover expenses and variations in industry activity that cause fluctuations in service provider costs. LOE increased 103% to $10.7 million in the first nine months of 2017, compared to $5.3 million for the same period of 2016. The increase largely relates to our increased production and well counts between periods, as we’ve incurred additional costs for equipment repair and maintenance, contract labor, chemicals, electricity, water disposal and equipment rental, all of which relate to the increased activity. LOE per Boe decreased 25% between periods to $2.68 for the nine months ended September 30, 2017, primarily because the increase in production between those two periods, came as a result of the addition of high-producing, low-operating cost wells.

Gathering and Transportation Expenses. Gathering and transportation expenses increased $1.7 million through the first nine months of 2017 compared to the same period of 2016 primarily due to increased production. In addition, we experienced an increase in our per unit gathering and transportation expense. The period over period increase in our per unit gathering and transportation expense is due to a shift away from marketing our natural gas under percent-of-proceeds contracts toward

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marketing a larger portion of our natural gas under fixed fee contracts. Under percent-of-proceeds contracts, we receive a percentage of the total proceeds received by the marketer, which is net of gathering and transportation costs. Conversely, under our fixed fee natural gas marketing contracts, our gas sales revenue is determined after transporting gas to a downstream sales point and we are separately charged for the associated gathering and transportation costs.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 244% between the nine months ended September 30, 2017 and 2016, from $3.2 million in 2016 to $10.9 million in 2017. The increase in production taxes is due to an increase in revenues, and the increase in ad valorem taxes relates to the addition of multiple new high-volume wells.

Exploration. The $2.5 million decrease in exploration expense between the nine months ended September 30, 2017 and 2016, is due to decreases in delay rentals on certain unproved properties of $1.3 million, as well as exploratory dry hole costs of $1.2 million incurred in 2016. The exploratory dry hole costs related to an unproductive vertical test well drilled to a shallow horizon.

Depletion, Depreciation, Amortization and Accretion. DD&A expense increased $37.8 million, or 128%, through the first nine months of 2017 compared to the same period of 2016. The increase in DD&A expense was largely due to an increase in production, partially offset by a decrease in our DD&A rate. Our DD&A rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The DD&A rate per Boe decreased 16% to $16.87 per Boe, compared to $20.13 per Boe in the first nine months of 2016. The decrease in our DD&A rate was largely due to an increase in reserve volumes due to continued successful drilling activities, whereas the rate of increase in capitalized costs related to those drilling activities was lower than the rate of reserve increase.

Impairment of Unproved Oil and Natural Gas Properties. During the first nine months of 2017, we incurred $0.4 million of impairment costs related to the expiration of certain leases on unproved properties. During the same period in 2016, we recorded $0.3 million of impairment expense related to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties in either period of 2017 or 2016.

Other Operating Expenses. Other operating expenses decreased $0.3 million from the first nine months of 2016 compared to the same period of 2017. We incurred $0.2 million of other operating expenses in the first nine months of 2017 primarily due to sales of fresh water and water disposal to third parties. During the first nine months of 2016, we incurred other operating expenses of $0.6 million due to rig termination fees of $0.2 million and $0.4 million of water sales costs.

General and Administrative and equity-based compensation. G&A (excluding equity-based compensation) increased 127% to $17.9 million for the nine months ended September 30, 2017, from $7.9 million for the same period of 2016. The increase is primarily due to an $8.3 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the growth of our capital expenditure program and production levels. The number of our full-time employees increased from 23 at January 1, 2016 to 56 at September 30, 2017. Additionally, we incurred $0.9 million in higher audit, tax and legal fees, which increase is largely driven from expenses as a result of becoming a publicly traded company.

Equity-based compensation expense in the first nine months of 2017 was $431.6 million, as summarized in the table below:



(in thousands)
Incentive unit awards	$	429,585
Restricted stock unit awards	1,191
Performance stock unit awards	866
Total equity-based compensation expense	$	431,642

Equity-based compensation expense for the incentive unit awards relates primarily to a $379.0 million charge for common stock issued to MIU holders that vested upon the IPO. In addition, incentive unit award compensation includes $50.6 million related to the common stock transferred to Management Holdco, which is subject to the terms of the Management Holdco LLC Agreement. Included in the $50.6 million is $22.2 million of equity-based compensation recognized during the first quarter of 2017 related to incentive unit awards which were modified in conjunction with a March 2017 separation agreement of a former executive officer. The RSUs and PSUs were granted during the second and third quarters of 2017. We expect to recognize additional noncash compensation expense of approximately $90.5 million over approximately 2.3 years for the incentive unit awards, and $11.5 million over approximately 2.3 years for the RSUs and PSUs.

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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)	2017			2016			Change
Gain (loss) on commodity derivatives	$	15,922		$	(8,208	)	$	24,130
Interest expense, net	(1,610		)	(1,471		)	(139		)
Other, net	474			—			474
Total other income (expense)	$	14,786		$	(9,679	)	$	24,465

Gain (loss) on Commodity Derivatives. Net gains and losses on our derivative instruments, as reflected in our statements of operations, are a function of fluctuations in the underlying commodity prices and the monthly settlement, if any, of the instruments. As a result, settlements on the contracts are included as a component of other income and expense as either a net gain or loss on derivative instruments. To the extent the future commodity price outlook declines between measurement periods, we will have noncash mark-to-market gains during the period. Conversely, to the extent future commodity price outlook increases between measurement periods, we will have noncash mark-to-market losses during the period.



	Nine Months Ended September 30,
(in thousands)	2017			2016
Gain (loss) on derivatives instruments, net	$	15,922		$	(8,208	)
Cash settlements of derivatives (received) paid, net	$	(3,691	)	$	1,159

Interest Expense, net. Interest expense relates to interest paid on the outstanding balance of the credit facility, commitment fees paid on the unused borrowing base and amortization of debt issuance costs, net of capitalized interest. The terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. During the first nine months of 2017 and 2016, we recorded $1.6 million and $1.5 million, respectively, of interest expense, net of capitalized interest, related to borrowings on our credit facility. The increased interest expense primarily relates to increased commitment fees due to a higher borrowing base, and higher amortization of debt issuance costs related to additional financing costs incurred throughout 2016 and the first part of 2017 related to borrowing base increases. This was partially offset by a decrease in interest paid, as our average outstanding debt balance during the first nine months of 2017 was $19.7 million, compared to $55.6 million for the same period of 2016. Our maximum debt outstanding during the first nine months of 2017 was $142.0 million in January, which was repaid in full in February with a portion of the proceeds from the IPO. During the first nine months of 2016, our maximum debt outstanding was $90.0 million in September.

Liquidity and Capital Resources

Historically, our predecessor’s primary sources of liquidity were capital contributions from its equity owners, borrowings under our predecessor’s credit facility and cash flows from operations. During the first nine months of 2017, our primary sources of liquidity were the proceeds from the IPO of $397.0 million, cash flows from operations of $105.4 million and borrowings on our credit facility of $35.0 million. Historically, our predecessor’s and our primary use of cash has been for the development and acquisition of oil, natural gas and NGL properties, as well as for 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 and production will be highly dependent on the capital resources available to us.

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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)	2017		2016		2017		2016
Acquisitions
Proved properties	$	—	$	7,482	$	—	$	7,482
Unproved properties⁽¹⁾	7,845		8,661		56,364		32,312
Development costs	158,870		36,845		399,057		82,651
Infrastructure costs⁽²⁾	3,613		3,956		21,805		7,311
Exploration costs	6		78		14		1,663
Total oil and gas capital expenditures	$	170,334	$	57,022	$	477,240	$	131,419


(1)	Relates to acquisition of undeveloped leaseholds and oil and natural gas mineral interest leasing activity.


(2)	Includes surface acreage purchased during the nine months ended September 30, 2017 and 2016 of $1.2 million and $0.5 million, respectively.

For the nine months ended September 30, 2017 and 2016, our capital expenditures have been focused on the acquisition and development of our properties in the Southern Delaware Basin. As of September 30, 2017, we had approximately 80,800 gross (72,600 net) acres in the Southern Delaware Basin.

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Gross wells
Operated	11	2	32	6
Non-operated	3	—	5	—
	14	2	37	6
Net wells
Operated	10.2	2.0	30.9	5.9
Non-operated	1.4	—	1.9	—
	11.6	2.0	32.8	5.9

At September 30, 2017, we were in the process of drilling seven gross (6.7 net) wells and had nine gross (8.4 net) wells waiting on completion, including four gross (4.0 net) wells that were in process of being completed.

2017 Capital Budget

Our 2017 capital budget for development of oil and gas properties and infrastructure is as follows:



(in millions)
Drilling and completion	$	530.0	—	$	550.0
Water infrastructure	20.0		—	25.0
Total	$	550.0	—	$	575.0

Our 2017 capital budget excludes potential leasehold and/or surface acreage additions. Based on our 2017 capital budget, we anticipate that we will spud approximately 54 to 58 gross operated wells, and approximately 11 to 15 gross non-operated wells. 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

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equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, 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 our drilling program, we may lose a portion of our acreage through lease expirations. In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means 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 credit facility to execute our remaining 2017 capital program and anticipated 2018 activities. 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 credit facility, joint venture partnerships, production payment 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 current drilling program, which could result in a loss of acreage through lease expirations. 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.

Working Capital

Our working capital, which we define as current assets minus current liabilities, fluctuates primarily as a result of our realized commodity prices, increases or decreases in our production volumes, changes in receivables and payables related to our operating and development of oil and natural gas activities, changes in our hedging activities and changes in our cash and cash equivalents. At September 30, 2017, our working capital was a deficit of $80.6 million, compared to a deficit of $31.0 million at December 31, 2016.

We may incur additional working capital deficits in the future due to liabilities that accrue related to our drilling program. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled approximately $3.9 million and $11.7 million at September 30, 2017 and December 31, 2016, respectively. We expect that our existing cash balances, cash flows from operating activities and availability under our credit facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, and commodity prices for our oil and natural gas production will be the largest variables affecting our working capital.

Cash Flows

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



	Nine Months Ended September 30,
(in thousands)	2017			2016
Net cash provided by operating activities	$	105,428		$	16,822
Net cash used in investing activities	$	(413,135	)	$	(125,984	)
Net cash provided by financing activities	$	299,880		$	100,417

Operating Activities. Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. For the first nine months of 2017 compared to 2016, the $88.6 million increase in net cash provided by operating activities primarily resulted from a period-over-period increase in revenues. This was partially offset by higher operating costs, primarily due to increased production.

Investing Activities. For the first nine months of 2017, net cash flow used in investing activities was $413.1 million, an increase of $287.2 million, or 228%, from $126.0 million for the same period of 2016. In the first nine months of 2017, net cash used for investing activities included investments in developing our acreage of $349.2 million and leasehold and acquisition costs of $60.6 million. In the first nine months of 2016, net cash used for investing activities included $84.8 million and $39.3 million for the development and acquisition of oil and natural gas properties, respectively.

Financing Activities. Net cash provided by financing activities during the first nine months of 2017 was primarily due to $398.4 million of net proceeds from the sale of common stock in the IPO and $45.0 million of borrowings on our credit

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facility, which was partially offset by a repayment on our credit facility of $142.0 million after the IPO. Net cash provided by financing activities in 2016 included $31.5 million of cash provided by equity issuances and $70.0 million of borrowings under our credit facility.

Credit Facility

On June 19, 2015, our predecessor entered into a credit agreement that provided for a senior secured revolving credit facility with an aggregate commitment of $500.0 million (subject to the then-effective borrowing base). In January 2017, the borrowing base increased to $180.0 million. In connection with the IPO, we, as parent guarantor, and our predecessor, as borrower, entered into an Amended and Restated Credit Facility. The Amended and Restated Credit Facility matures on February 1, 2022. After giving effect to such amendment and restatement, the aggregate principal commitment increased to $1.0 billion and the borrowing base under the Amended and Restated Credit Facility remained at $180.0 million. Also in connection with the IPO, we fully repaid the outstanding borrowings under the credit facility of $142.0 million. In April 2017, the borrowing base was increased to $250.0 million, and in October 2017 we entered into Amendment No. 1 to the Amended and Restated Credit Facility which increased the borrowing base to $425.0 million. As of the date of this filing, we have $80.0 million outstanding, and $345.0 million available under the borrowing base.

The amount available to be borrowed under our Amended and Restated Credit Facility is subject to a borrowing base that is redetermined semiannually by each April 1 and October 1 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, respectively. The borrowing base depends on, among other things, the volumes of our proved reserves, estimated cash flows from those reserves, our commodity hedge positions and any other outstanding debt. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, we could be required to immediately repay a portion of the debt outstanding under our credit facility. The most recent redetermination was completed in October 2017 and resulted in a borrowing base increase to $425.0 million.

At September 30, 2017, we paid a commitment fee on unused amounts of our Amended and Restated Credit Facility of 0.50% per annum. As a result of Amendment No. 1, the commitment fee now ranges from 0.375% to 0.50% per year, depending on the relative amount of the loan outstanding. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

Our Amended and Restated Credit Facility contains restrictive covenants that limit our ability to, among other things:


•	incur additional indebtedness;


•	incur liens;


•	make investments;


•	make loans to others;


•	merge or consolidate with another entity;


•	sell assets;


•	make certain payments;


•	enter into transactions with affiliates;


•	hedge interest rates; and


•	engage in certain other transactions without the prior consent of the lenders.

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:

•

a current ratio, which is the ratio of our consolidated current assets (including unused commitments under our credit facility and excluding noncash assets related to asset retirement obligations and derivatives) to our consolidated current liabilities (excluding the current portion of long-term debt under our credit facility and noncash liabilities related to asset retirement obligations and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and


•	a leverage ratio, which is the ratio of our consolidated Debt (as defined in our credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in our credit agreement) to EBITDAX (as defined in our credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0.

As of September 30, 2017, we were in compliance with all financial covenants.

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The Amended and Restated Credit Facility permits us to hedge up to the greater of 85% of proved reserves and 75% of our reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years.

Contractual Obligations

A summary of our contractual obligations as of September 30, 2017 is provided in the following table:



	Remainder		Payments Due by Period for the Year Ending December 31,
(in thousands)	of 2017		2018		2019		2020		2021		2022		Thereafter		Total
Credit facility⁽¹⁾	$	—	$	—	$	—	$	—	$	—	$	35,000	$	—	$	35,000
Operating leases⁽²⁾	349		1,550		1,287		1,514		1,535		1,552		8,962		16,749
Service and purchase contracts⁽³⁾	436		2,379		1,286		1,285		750		—		—		6,136
Rig contracts⁽⁴⁾	8,793		15,724		—		—		—		—		—		24,517
Frac fleet contracts⁽⁵⁾	13,800		73,200		—		—		—		—		—		87,000
Total	$	23,378	$	92,853	$	2,573	$	2,799	$	2,285	$	36,552	$	8,962	$	169,402

(1)

This table does not include future commitment fees, interest expense or other costs related to our 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, 2017, we had $35.0 million outstanding under our Amended and Restated Credit Facility and $215.0 million of borrowing capacity available.


(2)	Primarily relates to the lease of our corporate offices.


(3)	Primarily relates to a retail power sales agreement and seismic data gathering contract.


(4)	Relates to seven drilling rig contracts as of September 30, 2017. If we were to terminate these contracts at September 30, 2017, we would be required to pay early termination penalties of approximately $11.1 million.

(5)

Relates to three frac fleets under contract as of September 30, 2017. The majority of the contracts allow for reassignment of the frac fleets if we were to terminate their services prior to the end of the contract, at which point we would not be required to pay termination fees. However, if the fleets were not able to be reassigned, we would be required to pay termination fees of $66.2 million as of September 30, 2017.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of September 30, 2017. Please read Note 10, Commitments and Contingencies, included in the notes to our consolidated and combined financial statements included in this Quarterly Report on Form 10-Q, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

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 2016 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for successful efforts method of accounting for oil and natural gas activities, impairment of oil and natural gas properties, oil and natural gas reserve quantities, derivative instruments, and asset retirement obligations. 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 and combined 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 and combined 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.

Equity-Based Compensation

In connection with the IPO, we adopted the Jagged Peak Energy Inc. 2017 Long Term Incentive Plan (the “Plan”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. See “Part III,

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Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2016 for additional information related to the Plan.

We recognize compensation cost related to all equity-based awards in the financial statements based on their estimated grant-date fair value. We may grant various types of equity-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions) and restricted stock units (including awards with service-based vesting and market condition-based vesting provisions). Service-based restricted stock units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock units are based on the grant-date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period, and forfeitures are recognized as they occur.

Income Taxes

We are a subchapter C-corporation and are subject to U.S. federal and state income taxes. Income taxes are accounted for under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which we operate for the year in which those temporary differences are expected to be recovered or settled. We classify all deferred tax assets and liabilities as noncurrent. We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on technical merits, that the position will be sustained upon examination. Deferred tax assets are then reduced by a valuation allowance if we believe it is more-likely-than-not such deferred tax assets will not be realized.

Recent Accounting Pronouncements

Please refer to Note 2, Significant Accounting Policies and Related Matters – Recent Accounting Pronouncements, to the consolidated and combined financial statements included in this Quarterly Report on Form 10-Q for a discussion of recent accounting pronouncements and their anticipated effect on our business.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates, as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

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 been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our oil, natural gas and NGLs production depend on numerous factors beyond our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

For the nine months ended September 30, 2017, oil sales contributed 91% of our total production revenue, while natural gas sales contributed 3% and NGL sales contributed 6%. A $1.00 per barrel change in our realized oil price would have resulted in a $3.2 million change in oil revenues through the nine months ended September 30, 2017. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.2 million change in our natural gas revenues for the nine months ended September 30, 2017. A $1.00 per barrel change in NGL prices would have changed NGL revenue by $0.4 million for the nine months ended September 30, 2017. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

Due to this volatility, we use commodity derivative instruments such as swaps, basis swaps and collars to hedge price risk associated with our oil production. These hedging instruments allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. This provides increased certainty of cash flows for funding our development program and debt service requirements. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. We may seek to hedge price risk associated with our natural gas and NGL production in the future.

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Under our credit facility as of September 30, 2017, we are permitted to hedge up to the greater of 85% of our proved reserves and 75% of our reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years from the contract date.

At September 30, 2017, we had a net liability position of $0.6 million related to our oil derivatives in place for the years 2017 through 2019. Based on our open oil derivative positions at September 30, 2017, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $45.4 million. Conversely, a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $45.4 million.

See Note 3, Derivative Instruments, and Note 4, Fair Value Measurements, to our consolidated and combined financial statements included elsewhere in this report 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.

Counterparty and Customer Credit Risk

Our 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 members or affiliates of lenders of our bank credit facility.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We have little ability to control whether these entities will participate in our wells.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our credit facility. The terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. At September 30, 2017, we had $35.0 million of debt outstanding, all of which was under our Amended and Restated Credit Facility, with a weighted average interest rate of 3.49%. At September 30, 2017, borrowings under the Amended and Restated Credit Facility bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 1.25% to 2.25% in the case of the alternative base rate and from 2.25% to 3.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company pays a commitment fee of 0.50% per year on the unused portion of the borrowing base.

Borrowings under the Amended and Restated Credit Facility following Amendment No. 1 bear interest at a rate we elect that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate, and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We pay a commitment fee of 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.

At September 30, 2017, 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 $0.4 million on an annual basis. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

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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, 2017. 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, 2017 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, including workers’ compensation claims and employment related disputes. 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. For a discussion of our potential risks and uncertainties, see the information in Part I, Item 1A, Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes to our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2016.


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

None.


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
*10.1†		Form of Employment Letter Agreement of J. Jay Stratton, Jr. (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q filed with the SEC on August 10, 2017).
*10.2		Amendment No. 1, Master Assignment, and Agreement to Amended and Restated Credit Agreement, dated as of October 26, 2017, among Jagged Peak Energy LLC, as borrower, the guarantors party named therein, Wells Fargo Bank, National Association, as administrative agent and as issuing lender, the lenders named therein, the assignors named therein, and the assignees named therein.
*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		XBRL Instance Document
*101.SCH		XBRL Schema Document
*101.CAL		XBRL Calculation Linkbase Document
*101.LAB		XBRL Label Linkbase Document
*101.PRE		XBRL Presentation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document


†		Compensatory plan or arrangement.
*		Filed herewith.
**		Furnished herewith.

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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 8, 2017	By:	/s/ JOSEPH N. JAGGERS
			Name:	Joseph N. Jaggers
			Title:	Chairman, Chief Executive Officer and President

Date:	November 8, 2017	By:	/s/ ROBERT W. HOWARD
			Name:	Robert W. Howard
			Title:	Executive Vice President, Chief Financial Officer

Date:	November 8, 2017	By:	/s/ SHONN D. STAHLECKER
			Name:	Shonn D. Stahlecker
			Title:	Controller

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