Jagged Peak Energy Inc. - FORM 10-Q

Jagged Peak Energy Inc. - FORM 10-Q - August 9, 2018

Attached files

Attached files

Jagged Peak Energy Inc. Reports

file	filename
EX-32.2 - EXHIBIT 32.2 - Jagged Peak Energy Inc.	exhibit322q22018.htm
EX-32.1 - EXHIBIT 32.1 - Jagged Peak Energy Inc.	exhibit321q22018.htm
EX-31.2 - EXHIBIT 31.2 - Jagged Peak Energy Inc.	exhibit312q22018.htm
EX-31.1 - EXHIBIT 31.1 - Jagged Peak Energy Inc.	exhibit311q22018.htm
EX-10.2 - EXHIBIT 10.2 - Jagged Peak Energy Inc.	exhibit102q22018.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 June 30, 2018

¨ 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)



1401 Lawrence Street, Suite 1800 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 213,179,232 shares of common stock outstanding at August 3, 2018.

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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 June 30, 2018 and December 31, 2017	4

	Consolidated and Combined Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017	5

	Consolidated and Combined Statement of Changes in Equity for the Six Months Ended June 30, 2018	6

	Consolidated and Combined Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	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	39

Item 4.	Controls and Procedures	40

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 3.	Defaults Upon Senior Securities	41

Item 4.	Mine Safety Disclosures	41

Item 5.	Other Information	41

Item 6.	Exhibits	42


Signatures		43

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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, 2017, in “Part II. Other Information - Item 1A. Risk Factors” of this Quarterly Report, and in “Item 8.01, Other Events” in our Current Report on Form 8-K filed with the Securities and Exchange Commission on April 23, 2018.

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 2018;


•	our expected timing of the exchange offer of our senior notes issued in May 2018;


•	our expected noncash compensation expenses;


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


•	the timing and amount of our future production of oil, natural gas and NGLs;


•	our future drilling plans, including the number of wells anticipated to be brought online in 2018;


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


•	our pending legal or environmental matters;


•	our marketing of oil, natural gas and NGLs;


•	our leasehold or business acquisitions;


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


•	our hedging strategy and results;


•	general economic conditions;


•	uncertainty regarding our future operating results; 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, 2017, in “Part II. Other Information - Item 1A. Risk Factors” of this Quarterly Report, and in “Item 8.01, Other Events” in our Current Report on Form 8-K filed with the Securities and Exchange Commission on April 23, 2018.

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

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justify revisions of estimates that were made previously. If significant, such revisions could impact our strategy and change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

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



	June 30,			December 31,
	2018			2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	135,492		$	9,523
Accounts receivable	68,137			50,734
Derivative instruments	48,129			—
Other current assets	1,951			806
Total current assets	253,709			61,063
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method	1,598,172			1,195,831
Accumulated depletion	(268,398		)	(166,592		)
Total oil and gas properties, net	1,329,774			1,029,239
Other property and equipment, net	9,517			9,708
Total property and equipment, net	1,339,291			1,038,947
OTHER NONCURRENT ASSETS
Unamortized debt issuance costs	4,106			3,273
Derivative instruments	5,178			26
Other assets	119			119
Total noncurrent assets	9,403			3,418
TOTAL ASSETS	$	1,602,403		$	1,103,428
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	25,243		$	382
Accrued liabilities	126,791			132,311
Derivative instruments	75,117			41,782
Total current liabilities	227,151			174,475
LONG-TERM LIABILITIES
Long-term debt	488,906			155,000
Derivative instruments	17,593			11,095
Asset retirement obligations	1,277			811
Deferred income taxes	79,995			57,943
Other long-term liabilities	4,600			4,759
Total long-term liabilities	592,371			229,608
Commitments and contingencies
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value; 50,000,000 shares authorized, none issued	—			—
Common stock, $0.01 par value; 1,000,000,000 shares authorized, 213,179,232 shares issued at June 30, 2018; 212,930,655 shares issued at December 31, 2017	2,132			2,129
Additional paid-in capital	851,529			773,674
Accumulated deficit	(70,780		)	(76,458		)
Total stockholders’ equity	782,881			699,345
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,602,403		$	1,103,428

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 June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
REVENUES
Oil sales	$	148,614		$	48,388		$	269,337		$	85,153
Natural gas sales	2,338			1,841			5,213			2,758
NGL sales	7,599			2,663			12,907			4,181
Other operating revenues	125			159			272			347
Total revenues	158,676			53,051			287,729			92,439
OPERATING EXPENSES
Lease operating expenses	10,486			3,890			20,206			5,500
Gathering and processing expenses	—			655			—			1,047
Production and ad valorem taxes	9,246			3,537			16,920			6,177
Exploration	1			2			1			8
Depletion, depreciation, amortization and accretion	54,915			22,311			102,892			36,373
Impairment of unproved oil and natural gas properties	—			101			53			108
General and administrative expenses (including equity-based compensation of $2,379 and $10,775 for the three months ended June 30, 2018 and 2017, respectively, and $78,057 and $419,739 for the six months ended June 30, 2018 and 2017, respectively)	10,833			18,220			97,150			431,771
Other operating expenses	24			47			46			182
Total operating expenses	85,505			48,763			237,268			481,166
INCOME (LOSS) FROM OPERATIONS	73,171			4,288			50,461			(388,727		)
OTHER INCOME (EXPENSE)
Gain (loss) on commodity derivatives	(9,584		)	26,573			(13,910		)	43,615
Interest expense, net	(6,108		)	(432		)	(8,839		)	(1,143		)
Other, net	10			243			18			414
Total other income (expense)	(15,682		)	26,384			(22,731		)	42,886
INCOME (LOSS) BEFORE INCOME TAX	57,489			30,672			27,730			(345,841		)
Income tax expense (benefit)	12,408			14,269			22,052			103,637
NET INCOME (LOSS)	45,081			16,403			5,678			(449,478		)
Less: Net loss attributable to Jagged Peak Energy LLC (predecessor)	—			—			—			(375,476		)
NET INCOME (LOSS) ATTRIBUTABLE TO JAGGED PEAK ENERGY INC. STOCKHOLDERS	$	45,081		$	16,403		$	5,678		$	(74,002	)

Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share:
Basic	$	0.21		$	0.08		$	0.03		$	(0.35	)
Diluted	$	0.21		$	0.08		$	0.03		$	(0.35	)

Weighted average common shares outstanding:
Basic	213,142			212,932			213,073			212,934
Diluted	213,262			213,051			213,169			212,934

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)



	Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Stockholders' Equity
	Shares	Amount		Additional Paid-in Capital			Accumulated Deficit			Total Stockholders' Equity
BALANCE AT DECEMBER 31, 2017	212,931	$	2,129	$	773,674		$	(76,458	)	$	699,345
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	248	3		(202		)	—			(199		)
Equity-based compensation	—	—		78,057			—			78,057
Net income (loss)	—	—		—			5,678			5,678
BALANCE AT JUNE 30, 2018	213,179	$	2,132	$	851,529		$	(70,780	)	$	782,881

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)



	Six Months Ended June 30,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	5,678		$	(449,478	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion expense	102,892			36,373
Impairment of unproved oil and natural gas properties	53			108
Amortization of debt issuance costs	1,021			260
Deferred income taxes	22,052			103,637
Equity-based compensation	78,057			419,739
(Gain) loss on commodity derivatives	13,910			(43,615		)
Net cash receipts (payments) on settled derivatives	(27,358		)	496
Other	(156		)	(83		)
Change in operating assets and liabilities:
Accounts receivable and other current assets	(18,549		)	(8,710		)
Other assets	—			(119		)
Accounts payable and accrued liabilities	22,214			1,397
Net cash provided by operating activities	199,814			60,005
CASH FLOWS FROM INVESTING ACTIVITIES
Leasehold and acquisition costs	(11,053		)	(52,968		)
Development of oil and natural gas properties	(392,968		)	(195,212		)
Other capital expenditures	(1,881		)	(1,456		)
Net cash used in investing activities	(405,902		)	(249,636		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from senior notes	500,000			—
Proceeds from credit facility	165,000			10,000
Repayment of credit facility	(320,000		)	(142,000		)
Debt issuance costs	(12,743		)	(1,421		)
Proceeds from issuance of common stock in initial public offering, net of underwriting fees	—			401,625
Costs relating to initial public offering	—			(3,216		)
Employee tax withholding for settlement of equity compensation awards	(200		)	(88		)
Net cash provided by financing activities	332,057			264,900
NET CHANGE IN CASH AND CASH EQUIVALENTS	125,969			75,269
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	9,523			11,727
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	135,492		$	86,996
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest	$	3,813		$	1,001
Cash paid for income taxes	—			—
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	102,306		$	93,834
Asset retirement obligations	426			246

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

Corporate Reorganization and Initial Public Offering

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

Immediately prior to the IPO, a corporate reorganization (the “corporate reorganization”) took place whereby JPE LLC became a wholly owned subsidiary 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 31,599,334 shares of common stock to the public, which included 3,266,000 shares sold by the selling stockholders. The stock was priced at $15.00 per share and the Company received net proceeds of approximately $397.0 million after deducting offering expenses and underwriting discounts and commissions. The Company did not receive any proceeds from the sale of the shares by the selling stockholders.

Additional background on the Company and its IPO, along with details of the ownership of the Company are available in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”).

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 2017 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 and combined financial statements included in the 2017 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 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 Note 5, Equity-based Compensation, and Note 7, Income Taxes, respectively.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Note 2—Significant Accounting Policies and Related Matters

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 2, Significant Accounting Policies and Related Matters, to the Company’s consolidated and combined financial statements in its 2017 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, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Estimates made in preparing these consolidated and combined financial statements include, among other things, (1) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment of oil and natural gas properties, (2) operating and capital costs accrued, (3) estimates of timing and costs used in calculating asset retirement obligations, (4) estimates of the fair value of equity-based compensation, (5) estimates used in developing fair value assumptions and estimates, (6) estimates of deferred income taxes and (7) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in estimates, assumptions or actual results could have a significant impact on results in future periods.

Revenue Recognition

On January 1, 2018, the Company adopted Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, (“ASC 606”) using the modified retrospective approach, which only applied to contracts that were in effect as of the date of adoption. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and did not impact the Company’s previously reported results of operations, nor its ongoing consolidated and combined balance sheets, statements of cash flow or statement of changes in equity.

Under ASC 606, oil, natural gas and NGL sales revenues are recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Company’s oil, natural gas and NGL sales are made under contracts with customers. The performance obligations for the Company’s contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery. The Company’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions.

Under the Company’s current gas processing contracts, it delivers natural gas to a purchaser at or near the wellhead. For these contracts, the Company has concluded the purchaser is the customer, and as such, the Company recognizes natural gas and NGLs revenues based on the net amount of proceeds it receives from the purchaser.

The Company’s product types are as follows:

Oil Sales. Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser at or near the wellhead, and collects a contractually agreed upon index price, net of pricing and gathering and transportation differentials. The Company transfers control of the product to the purchaser at or near the wellhead and recognizes revenue based on the net price received.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Natural Gas and NGL Sales. Under the Company’s natural gas sales contracts, the Company delivers and transfers control of natural gas to the purchaser at delivery points at or near the wellhead. The purchaser gathers and processes the natural gas and sells the resulting residue gas and NGLs to purchasers. The Company receives its contractual portion of the proceeds for the sale of the residue gas and NGLs at an agreed upon index price, net of pricing differentials and applicable selling expenses including gathering, processing and fractionation costs. The Company recognizes revenue at the expected net price when control transfers to the purchaser.

The Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which the variable consideration is allocated entirely to a wholly unsatisfied performance obligation, as allowed under ASC 606. Under the Company’s oil, natural gas and NGL sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Disaggregation of Revenue

The Company’s oil, natural gas and NGL sales revenues represent substantially all of its revenues, and are derived from the sale of oil, natural gas and NGL production within the Permian Basin. The Company believes the disaggregation of revenues into the three product types of oil sales, natural gas sales and NGL sales, as seen on the consolidated and combined statements of operations, is an appropriate level of detail for its primary activity.

Accounts Receivable

At June 30, 2018 and December 31, 2017, accounts receivable was comprised of the following:



(in thousands)	June 30, 2018		December 31, 2017
Oil and gas sales	$	49,009	$	42,869
Joint interest	17,383		7,860
Other	1,745		5
Total accounts receivable	$	68,137	$	50,734

At June 30, 2018 and December 31, 2017, the Company did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented.

Oil and Natural Gas Properties

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



(in thousands)	June 30, 2018			December 31, 2017
Proved oil and natural gas properties	$	1,420,427		$	1,012,321
Unproved oil and natural gas properties	177,745			183,510
Total oil and natural gas properties	1,598,172			1,195,831
Less: Accumulated depletion	(268,398		)	(166,592		)
Total oil and natural gas properties, net	$	1,329,774		$	1,029,239

Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement costs, are depleted based on proved developed reserves on a field basis. For the three months ended June 30, 2018 and 2017, the Company recorded depletion for oil and natural gas properties of $54.4 million and $21.9 million, respectively. For the six months ended June 30, 2018 and 2017, the Company recorded depletion for oil and natural gas properties of $101.8 million and $35.5 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated and combined statements of operations.

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Notes to Consolidated and Combined Financial Statements

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Accrued Liabilities

The components of accrued liabilities are shown below:



(in thousands)	June 30, 2018		December 31, 2017
Accrued capital expenditures	$	89,756	$	102,956
Accrued accounts payable	7,144		8,488
Royalties payable	8,596		6,105
Accrued LOE	7,827		5,736
Other current liabilities	13,468		9,026
Total accrued liabilities	$	126,791	$	132,311

Recent Accounting Pronouncements

Recently Adopted Accounting Standards

Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlined a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most prior revenue recognition guidance, including industry-specific guidance. The Company adopted the new standard on January 1, 2018, as described above. The Company implemented the necessary changes to its business processes, systems and controls to support recognition and disclosure of this new standard.

The Company’s financial statement presentation related to revenue received from certain gas sales contracts changed as a result of the new standard. Under previous guidance, proceeds from certain gas sales contracts were reported gross, with related costs for gathering and processing being presented separately as gathering and processing expense. Upon adoption of the new standard, the Company presents revenue from these contracts net of gathering and processing costs, as these costs are incurred after control of the product is transferred to the customer. The impact of the new revenue recognition standard on the Company’s current period results is as follows:



	Three Months Ended June 30, 2018
(in thousands)	Amounts presented on statements of operations		ASC 606 Adjustments		Previous Revenue Recognition Method
Revenues
Oil sales	$	148,614	$	—	$	148,614
Natural gas sales	2,338		986		3,324
NGL sales	7,599		2,986		10,585
Other operating revenues	125		—		125
Total revenues	$	158,676	$	3,972	$	162,648

Operating expenses
Gathering and processing expenses	$	—	$	3,972	$	3,972

Net income (loss)	$	45,081	$	—	$	45,081

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	Six Months Ended June 30, 2018
(in thousands)	Amounts presented on statements of operations		ASC 606 Adjustments		Previous Revenue Recognition Method
Revenues
Oil sales	$	269,337	$	—	$	269,337
Natural gas sales	5,213		1,885		7,098
NGL sales	12,907		4,601		17,508
Other operating revenues	272		—		272
Total revenues	$	287,729	$	6,486	$	294,215

Operating expenses
Gathering and processing expenses	$	—	$	6,486	$	6,486

Net income (loss)	$	5,678	$	—	$	5,678

Adoption of the new standard did not impact the Company’s previously reported results of operations or consolidated and combined cash flows statements.

Stock Compensation - Scope of Modification Accounting. In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting. The ASU clarified which changes to the terms or conditions of an equity-based payment award require an entity to apply modification accounting in Topic 718. The standard became effective for the Company on January 1, 2018. The adoption of this new standard did not impact the Company’s consolidated and combined statements of operations, balance sheets or cash flows.

Accounting Standards Not Yet Adopted

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires all leases with a term greater than one year to be recognized on the balance sheet as right-of-use assets and lease liabilities. ASU 2016-02 retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. The update does not apply to leases of mineral rights to explore for or use oil and natural gas. Under ASU 2016-02, entities are required to adopt the new standard using a modified retrospective approach and apply the provisions of ASU 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Company's adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11, Targeted Improvements, which provides entities an optional transitional relief method whereby prior periods would not require restatement while a cumulative adjustment to retained earnings during the period of adoption would be recorded. The Company continues its evaluation of the impact of ASU 2016-02, as amended, which includes an analysis of existing contracts, including drilling rig and frac fleet contracts, office leases and certain equipment. The Company is also evaluating the effect of ASU 2016-02, as amended, on its current accounting policies, disclosures and controls. The Company intends to adopt the new standard on January 1, 2019 using the optional transitional relief method provided for in ASU 2018-11. The Company believes that adopting the standard will result in increases to the assets and liabilities on its consolidated and combined balance sheets, and changes to the timing and presentation of certain operating expenses on its consolidated and combined statements of operations. The Company continues to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust its implementation strategies as necessary.

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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 9, Fair Value Measurements.

In an effort to reduce the variability of the Company’s cash flows, the Company hedged the commodity prices associated with a portion of its expected future oil volumes by entering into swap and basis swap derivative financial instruments. With swaps, the Company typically receives an agreed upon fixed price for a specified notional quantity of oil or natural gas, and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices. Basis swap contracts establish the differential between Cushing WTI prices and Midland WTI prices for the notional volumes contracted. The Company’s commodity derivatives may expose it to the risk of financial loss in certain circumstances. The Company’s derivative arrangements provide protection on the hedged volumes if market prices decline below the prices at which these derivatives are set. If market prices rise above the prices at which the Company has hedged, the Company will be required to make settlement payments to its derivative counterparties.

The following table summarizes the Company’s derivative contracts as of June 30, 2018:



Contract Period	Volumes (Bbls)	Wtd Avg Price ($/Bbl)
Oil Swaps: ⁽¹⁾
Third quarter 2018	1,803,200	$	55.39
Fourth quarter 2018	1,789,400	$	55.66
Total 2018	3,592,600	$	55.52
Year ending December 31, 2019	4,015,000	$	55.48
Year ending December 31, 2020	732,000	$	59.17
Oil Basis Swaps: ⁽²⁾
Third quarter 2018	1,610,000	$	(2.27	)
Fourth quarter 2018	1,610,000	$	(2.27	)
Total 2018	3,220,000	$	(2.27	)
Year ending December 31, 2019	3,285,000	$	(1.88	)
Year ending December 31, 2020	3,294,000	$	(1.08	)


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


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

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

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Notes to Consolidated and Combined Financial Statements

(Unaudited)

Subsequent to June 30, 2018, the Company entered into the following additional derivative contracts:



Contract Period	Volumes (Bbls)	Wtd Avg Price ($/Bbl)
Oil Swaps: ⁽¹⁾
Year ending December 31, 2019	3,650,000	$	64.88
Year ending December 31, 2020	2,196,000	$	61.37
Oil Basis Swaps: ⁽²⁾
Year ending December 31, 2019	5,478,000	$	(8.34	)
Year ending December 31, 2020	6,222,000	$	(1.43	)


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


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

The Company recognized the following gains (losses) and net cash receipts (payments) in earnings for the periods indicated:



	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2018			2017		2018			2017
Gain (loss) on derivative instruments, net	$	(9,584	)	$	26,573	$	(13,910	)	$	43,615
Net cash receipts (payments) on settled derivatives	$	(11,879	)	$	1,567	$	(27,358	)	$	496

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 June 30, 2018 and December 31, 2017 (in thousands):



As of June 30, 2018:	Balance Sheet Location	Gross amounts presented on the balance sheet		Netting adjustments not offset on the balance sheet			Net amounts
Assets
Commodity contracts	Current assets - derivative instruments	$	48,129	$	(28,302	)	$	19,827
Commodity contracts	Noncurrent assets - derivative instruments	5,178		(5,178		)	—
Total assets		$	53,307	$	(33,480	)	$	19,827
Liabilities
Commodity contracts	Current liabilities - derivative instruments	$	75,117	$	(28,302	)	$	46,815
Commodity contracts	Noncurrent liabilities - derivative instruments	17,593		(5,178		)	12,415
Total liabilities		$	92,710	$	(33,480	)	$	59,230

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Notes to Consolidated and Combined Financial Statements

(Unaudited)



As of December 31, 2017:	Balance Sheet Location	Gross amounts presented on the balance sheet		Netting adjustments not offset on the balance sheet			Net amounts
Assets
Commodity contracts	Current assets - derivative instruments	$	—	$	—		$	—
Commodity contracts	Noncurrent assets - derivative instruments	26		(26		)	—
Total assets		$	26	$	(26	)	$	—
Liabilities
Commodity contracts	Current liabilities - derivative instruments	$	41,782	$	—		$	41,782
Commodity contracts	Noncurrent liabilities - derivative instruments	11,095		(26		)	11,069
Total liabilities		$	52,877	$	(26	)	$	52,851

Derivative Counterparty Risk

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

The Company’s counterparty credit exposure related to commodity derivative instruments comprises contracts with a net positive fair value at the reporting date. These outstanding instruments, if any, expose the Company to credit risk in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of the Company’s counterparties decline, its ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third-party. In the event of a counterparty default, the Company may sustain a loss and its cash receipts could be negatively impacted.

At June 30, 2018, the Company had commodity derivative contracts with six counterparties, all of which were lenders under the Company’s Amended and Restated Credit Facility (as defined in Note 4, Debt) and all of which had investment grade credit ratings. These counterparties accounted for all the Company’s counterparty credit exposure related to commodity derivative assets.

Note 4—Debt

The Company’s debt consisted of the following at June 30, 2018 and December 31, 2017:



(in thousands)	June 30, 2018			December 31, 2017
Senior secured revolving credit facility	$	—		$	155,000
5.875% senior unsecured notes due 2026	500,000			—
Debt issuance costs on senior unsecured notes	(11,094		)	—
Total long-term debt	$	488,906		$	155,000

Senior Secured Revolving Credit Facility

At December 31, 2017, the Company’s amended and restated credit facility, as amended (the “Amended and Restated Credit Facility”), had a borrowing base of $425.0 million, with $155.0 million outstanding. In March 2018, the Company entered into Amendment No. 2 to the Amended and Restated Credit Facility, which extended the maturity date of the Amended and Restated Credit Facility to March 21, 2023 and increased the borrowing base to $540.0 million. Borrowings under the Amended and Restated Credit Facility under Amendment No. 2 bear interest at a rate elected by the Company that is equal to an adjusted base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the adjusted base rate, and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the elected commitments. The Company also incurs a commitment fee that is

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Notes to Consolidated and Combined Financial Statements

(Unaudited)

between 0.375% to 0.50% per year on the unused portion of the elected commitments, depending on the relative amount of the loan outstanding in relation to the elected commitments.

In April 2018, and in connection with the issuance of the Senior Notes (as described and defined below), the lenders of the Amended and Restated Credit Facility agreed to waive a provision that would require a borrowing base reduction as a result of the Senior Notes. As a result, the borrowing base of the Amended and Restated Credit Facility continued to be $540.0 million as of June 30, 2018. The Company also voluntarily elected to reduce the elected commitments to $475.0 million, effective as of the closing of the Senior Notes offering. Additionally, a portion of the proceeds from the Senior Notes were used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received.

In June 2018, the Company entered into Amendment No. 3 to the Amended and Restated Credit Facility which increased the amount the Company is permitted to hedge up to 85% of forecasted future production for up to 36 months in the future, and up to the greater of 75% of its proved reserves and 60% of its reasonably anticipated forecasted production for 37 to 60 months in the future, provided that no hedges have a term beyond five years.

The Amended and Restated Credit Facility contains certain nonfinancial covenants, including among others, restrictions on: indebtedness, liens, investments, mergers, sales of assets, hedging activity, and dividends and payments to the Company’s capital interest holders.

The Amended and Restated Credit Facility also contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Facility, include requirements to comply with the following financial ratios:



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

As of June 30, 2018, the Company was in compliance with its Amended and Restated Credit Facility financial covenants.

In August 2018, the Company entered into Amendment No. 4 to the Amended and Restated Credit Facility which increased the borrowing base to $825.0 million and the Company increased its elected commitments to $540.0 million.

5.875% Senior Unsecured Notes due 2026

On May 8, 2018, JPE LLC issued $500.0 million aggregate principal amount of 5.875% senior unsecured notes that mature on May 1, 2026 (the “Senior Notes”) in a 144A private placement that was exempt from registration under the Securities Act. Interest is payable on the Senior Notes semi-annually in arrears on each May 1 and November 1, commencing November 1, 2018. The Senior Notes resulted in net proceeds to the Company, after deducting the initial purchasers’ discount and offering expenses, of $488.7 million. A portion of such proceeds was used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received. The remainder of the net proceeds are expected to be used to fund a portion of the Company’s 2018 capital program and for other general corporate purposes.

The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by Jagged Peak and may be guaranteed by future subsidiaries. Jagged Peak has no independent assets or operations and has no other subsidiaries other than JPE LLC. There are no significant restrictions on the Company’s ability to obtain funds from its subsidiary in the form of cash dividends or other distributions of funds.

In connection with the issuance of the Senior Notes, the Company entered into a registration rights agreement with the initial purchasers, dated May 8, 2018, to allow holders of the unregistered Senior Notes to exchange the unregistered Senior Notes for registered notes that have substantially identical terms. The Company agreed to use reasonable efforts to cause the exchange to be completed within 360 days after the issuance of the Senior Notes. The Company is required to pay additional interest if it fails to comply with its obligations to complete the exchange offer of the Senior Notes within the specified time period, whereby the interest rate would be increased by up to 1.0% per annum during the period in which a registration default

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Notes to Consolidated and Combined Financial Statements

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is in effect. The Company expects to comply with the terms of the registration rights agreement and complete the exchange of the Senior Notes within the 360-day period.

If the Company experiences certain defined changes of control, each holder of the Senior Notes may require the Company to repurchase all or a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes plus accrued and unpaid interest as of the date of repurchase, if any.

The indenture governing the Senior Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

Note 5—Equity-based Compensation

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 each type of equity-based compensation award for the periods indicated:



	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2018		2017		2018		2017
Incentive unit awards	$	559	$	9,929	$	75,158	$	418,893
Restricted stock unit awards	794		377		2,113		377
Performance stock unit awards	892		339		497		339
Restricted stock unit awards issued to nonemployee directors	134		130		289		130
Total equity-based compensation expense	$	2,379	$	10,775	$	78,057	$	419,739

Equity-based compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, modification of awards, employee forfeitures, and the timing of the awards.

For the six months ended June 30, 2018, equity-based compensation expense includes (1) $71.3 million related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO (as described further below) and (2) the reversal of equity-based compensation expense associated with awards that were forfeited, notably performance stock unit (“PSU”) awards forfeited by former executive officers. As the Company’s policy is to recognize forfeitures as they occur, previously recognized expense on unvested awards is reversed at the date of forfeiture. For the six months ended June 30, 2017, equity-based compensation expense for incentive unit awards of $419.7 million included (1) $379.0 million related to the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016, and (2) $22.2 million related to a modification in conjunction with a March 2017 separation agreement of a former executive officer.

In February 2018, certain employees notified the Company of their desire to terminate their employment. Under the terms of the JPE Management Holdings LLC limited liability company agreement (“Management Holdco LLC Agreement”), upon voluntary termination of employment by an incentive unit award holder, the Board of Directors has the discretion to allow outstanding unvested incentive unit awards to immediately vest, to continue to vest post-termination, and/or to be automatically forfeited, or any combination thereof. Any forfeited incentive units would be reallocated to the remaining incentive unit holders employed by the Company. In February 2018, the Board of Directors modified these employees’ unvested incentive units to either immediately accelerate vesting, in the case of retiring employees, or continue to vest post-termination under the original vesting period. The Company determined that these changes should be accounted for as modifications under ASC 718 in the first quarter of 2018. As a result of these modifications to the service requirements, the Company determined that, for accounting purposes under ASC 718, the incentive unit awards allocated at IPO no longer met the substantive service condition, and that any previously unrecognized equity-based compensation expense should be recognized immediately. The acceleration of all previously unrecognized equity-based compensation expense for incentive unit awards allocated at the time of the IPO resulted in the recognition of $71.3 million of noncash equity-based compensation expense in the first quarter of 2018. This

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Notes to Consolidated and Combined Financial Statements

(Unaudited)

accounting does not alter the legal service obligations under the Management Holdco LLC Agreement for remaining employees whose awards were not modified. Equity-based compensation expense recognition related to incentive unit awards that were unallocated at the time of the IPO is unaffected.

The following table summarizes the Company’s incentive unit award, restricted stock unit (“RSU”) award and PSU award activity for the six months ended June 30, 2018:



	Incentive Units ⁽²⁾			Restricted Stock Units ⁽³⁾			Performance Stock Units
Unvested at December 31, 2017	7,755,745			582,973			398,566
Awards Granted ⁽¹⁾	406,173			588,118			546,319
Vested	(2,789,511		)	(264,130		)	—
Forfeited	(73,307		)	(125,854		)	(253,522		)
Unvested at June 30, 2018	5,299,100			781,107			691,363
(1) Weighted average grant-date fair value	$	13.40		$	12.70		$	16.23


(2)	Included in the unvested incentive units at June 30, 2018 are 4,809,666 units for which equity-based compensation expense was accelerated and fully recognized in February 2018. See the discussion above for additional information.


(3)	Of the 588,118 RSUs granted during 2018, nonemployee directors received 30,753 at a weighted average grant-date fair value of $13.17.

The following table reflects the future equity-based compensation expense to be recorded for each type of award that was outstanding at June 30, 2018:



	Incentive Units		Restricted Stock Units ⁽¹⁾		Performance Stock Units
Compensation costs remaining at June 30, 2018 (in millions)	$	5.8	$	8.7	$	9.2
Weighted average remaining period at June 30, 2018 (in years)	2.6		2.4		2.4


(1)	The remaining compensation costs at June 30, 2018 for the nonemployee director RSUs was $0.4 million, with a weighted average remaining period of 0.9 years.

At June 30, 2018, there were 98,455 unallocated incentive units that are available to be granted. When these units are granted, they will be valued using the closing stock price on the date of grant, and the Company will recognize the related expense over the requisite service period.

Note 6—Earnings Per Share

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

For the six months ended June 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 June 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 June 30,				Six Months Ended		From January 27, 2017, to
(in thousands, except per share amounts)	2018		2017		June 30, 2018		June 30, 2017
Net income (loss) attributable to Jagged Peak Energy Inc. stockholders	$	45,081	$	16,403	$	5,678	$	(74,002	)

Basic weighted average shares outstanding	213,142		212,932		213,073		212,934
Dilutive restricted stock units	115		—		96		—
Dilutive performance stock units	5		119		—		—
Diluted weighted average shares outstanding	213,262		213,051		213,169		212,934

Net income (loss) per common share:
Basic	$	0.21	$	0.08	$	0.03	$	(0.35	)
Diluted	$	0.21	$	0.08	$	0.03	$	(0.35	)

The following table presents the weighted average number of outstanding equity awards that have been excluded from the computation of diluted earnings per common share as their inclusion would be anti-dilutive:



	Three Months Ended June 30,		Six Months Ended	From January 27, 2017, to
(in thousands)	2018	2017	June 30, 2018	June 30, 2017
Number of antidilutive units: ⁽¹⁾
Antidilutive restricted stock units	121	65	342	231
Antidilutive performance stock units	1	—	165	267


(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 7—Income Taxes

Income tax expense was as follows for the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2018			2017			2018			2017
Income tax expense	$	12,408		$	14,269		$	22,052		$	103,637
Effective tax rate	21.6		%	46.5		%	79.5		%	(30.0		)%

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 in the accompanying consolidated and combined financial statements. Included in the deferred federal income tax provision above for the six months ended June 30, 2017, is a $79.1 million income tax expense related to the Company’s change in tax status as a result of the corporate reorganization.

The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended June 30, 2018, the Company’s overall effective tax rate was different than the federal statutory rate of 21% primarily due to permanent differences on vested equity-based compensation awards. For the six months ended June 30, 2018, the Company’s overall effective tax rate was different than the federal statutory rate of 21% primarily due to nondeductible equity-based compensation related to incentive unit awards allocated at the time of the IPO, and permanent differences on vested equity-based compensation awards. For the three and six

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Notes to Consolidated and Combined Financial Statements

(Unaudited)

months ended June 30, 2017, the Company’s overall effective tax rate was different than the federal statutory rate of 35% primarily due to the impact of the change in tax status and nondeductible equity-based compensation.

On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). Due to the complexities involved in accounting for the enactment of the new law, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) 118 that allowed for a measurement period of up to one year after the enactment date of the Tax Act to finalize the impact of the Tax Act on a company's financial statements. The Company substantially completed its analysis of the Tax Act and recorded its estimated impact in the year ended December 31, 2017. As of June 30, 2018, the Company has not made any material adjustments to its provisional estimate at December 31, 2017. Any changes to the calculation that do arise will be recorded as they are identified during the measurement period provided for by SAB 118.

Note 8—Asset Retirement Obligations

The following table summarizes the changes in the carrying amount of the asset retirement obligations for the six months ended June 30, 2018. The current portion of the asset retirement obligation liability is included in accrued liabilities on the consolidated and combined balance sheets.



(in thousands)
Asset retirement obligations at January 1, 2018	$	929
Liabilities incurred and assumed	392
Liability settlements and disposals	(26		)
Revisions of estimated liabilities	35
Accretion	56
Asset retirement obligations at June 30, 2018	1,386
Less current portion of asset retirement obligations	(109		)
Long-term asset retirement obligations	$	1,277

Note 9—Fair Value Measurements

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

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.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

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

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Reclassifications of fair value among Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers among Level 1, Level 2 or Level 3 during the six months ended June 30, 2018.

Assets and liabilities measured on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis. The following table sets forth the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:



	Level 2
(in thousands)	June 30, 2018		December 31, 2017
Assets from commodity derivative contracts	$	53,307	$	26
Liabilities due to commodity derivative contracts	$	92,710	$	52,877

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

Fair Value of Other Financial Instruments

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



	June 30, 2018				December 31, 2017
(in thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt:
Senior secured revolving credit facility	$	—	$	—	$	155,000	$	155,000
5.875% senior unsecured notes due 2026	$	500,000	$	492,970	$	—	$	—

The fair value of the Amended and Restated Credit Facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes at June 30, 2018 was based on the quoted market price and is classified as Level 1 in the fair value hierarchy.

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are considered to be representative of their respective fair values due to the nature of and short-term maturities of those instruments.

Assets and liabilities measured on a nonrecurring basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. These assets and liabilities include the acquisition or impairment of proved and unproved oil and gas properties and the inception value of asset retirement obligation liabilities.

Proved oil and natural gas properties. The Company reviews its proved oil and natural gas properties for impairment whenever facts and circumstances indicate their carrying value may not be recoverable. In such circumstances, the income approach is used to determine the fair value of proved oil and natural gas reserves. Under this approach, the Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted cash flows to the carrying

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs.

Unproved oil and nature gas properties. Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Company uses a market approach, and takes into account future development plans, remaining lease term, drilling results and reservoir performance. These assumptions and estimates represent Level 3 inputs.

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



	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2018		2017		2018		2017
Proved oil and natural gas property impairments	$	—	$	—	$	—	$	—
Unproved oil and natural gas property impairments ⁽¹⁾	—		101		53		108
	$	—	$	101	$	53	$	108


(1)	The impairments of unproved oil and natural gas properties resulted from expirations of certain undeveloped leases.

Asset retirement obligations. The inception value and new layers resulting from upward revisions of the Company’s asset retirement obligations are also measured at fair value on a nonrecurring basis. The inputs used to determine such fair value are based primarily on the present value of estimated future cash outflows. Given the unobservable nature of these inputs, they represent Level 3 inputs.

Note 10—Commitments and Contingencies

Commitments

There were no material changes in commitments during the first six months of 2018. Please refer to Note 10, Commitments and Contingencies, in the 2017 Form 10-K for additional discussion.

Contingencies

Legal Matters

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

Environmental Matters

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

Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both June 30, 2018 and December 31, 2017, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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JAGGED PEAK ENERGY INC.

Notes to Consolidated and Combined Financial Statements

(Unaudited)

Note 11—Related Party Transactions

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2018		2017		2018		2017
Oryx via 3rd party shipper ⁽¹⁾	$	5,550	$	2,379	$	10,284	$	3,798
Oryx ⁽²⁾	$	85	$	303	$	300	$	652
Phoenix ⁽³⁾	$	112	$	117	$	221	$	202
Trident ⁽³⁾	$	—	$	—	$	—	$	236


(1)	Fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil transportation and gathering agreement are netted against revenue as they are included in the net price paid by to the third-party shipper.


(2)	Fees paid to Oryx for the purchase and installation of metering equipment are capitalized to proved properties on the consolidated and combined balance sheets.


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

At June 30, 2018 and December 31, 2017, the Company had outstanding payables to these related parties of $2.2 million and $1.8 million, respectively. See Note 11, Related Party Transactions, in the 2017 Form 10-K for more information.


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 and combined financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2017. 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” in this Quarterly Report on Form 10-Q, “Item 8.01, Other Events” in our Current Report on Form 8-K filed with the Securities and Exchange Commission on April 23, 2018 and “Part 1, Item 1A. Risk Factors” in our 2017 Form 10-K.

In this section, references to “Jagged Peak,” “the Company,” “we,” “us” and “our” refer to Jagged Peak Energy Inc. and its subsidiaries, after 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. JPE LLC, our accounting predecessor, was formed in 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves. 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; the Delaware Basin is a sub-basin of the Permian Basin. Our acreage is located on large, contiguous blocks in the adjacent Texas counties of Winkler, Ward, Reeves and Pecos, with significant original oil-in-place within multiple stacked hydrocarbon-bearing formations.

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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 June 30, 2018, our acreage position was approximately 79,300 net acres.

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 six months of 2017, our realized oil price for the first six months of 2018 increased 31% to $60.99 per barrel, our realized natural gas price declined 47% to $1.34 per Mcf, and our realized price for NGLs increased by 17% to $22.86 per barrel between these same periods. The realized natural gas and NGL prices during the first six months of 2018 were negatively impacted by the adoption of ASC 606, which requires us to deduct gathering and processing costs from revenue rather than record it as a separate expense. See below for further information regarding the “Adoption of ASC 606” related to the impact of the new revenue recognition standard on our natural gas and NGL revenues and corresponding realized prices, and “Sources of Our Revenues” 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.

Increased Oil and Natural Gas Development Activities

During the six months ended June 30, 2018, we brought online 38 gross (28.7 net) operated wells. Our average daily production has grown 154% from 12,263 Boe/d during the first six months of 2017 to 31,098 Boe/d for the same period of 2018. In the six months ended June 30, 2018, we spent $391.6 million on drilling and completing wells and on further developing our water infrastructure. This compares to $258.4 million that we spent in the six months ended June 30, 2017 for drilling, completion and infrastructure.

Equity-based Compensation

During the six months ended June 30, 2018, we recognized equity-based compensation expense of $78.1 million, which included $71.3 million related to a modification of service requirements for incentive unit awards. During the six months ended June 30, 2017, we recognized equity-based compensation of $419.7 million which included $379.0 million related to incentive unit awards that vested at the time of the IPO. Please refer to Note 5, Equity-based Compensation, in “Part I. Financial Information - Item 1. Financial Statements” for additional information on equity-based compensation.

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 during the six months ended June 30, 2017. For periods following completion of the corporate reorganization, we began recording income taxes associated with our status as a corporation. Please refer to Note 7, Income Taxes, in “Part I. Financial Information - Item 1. Financial Statements” for more information on income taxes.

The Tax Act, which was signed into law in December 2017, significantly changed the federal income taxation of business entities. The Tax Act, among other things, reduces the corporate income tax rate from 35% to 21%, partially limits the deductibility of business interest expense and net operating losses, allows the immediate deduction of certain new investments instead of deductions for depreciation expense over time and eliminates the corporate alternative minimum tax.

Adoption of ASC 606

As of January 1, 2018, we adopted ASC 606 using the modified retrospective method. This adoption did not have an impact on the opening balance of retained earnings. As a result of the adoption, we changed the presentation of the costs to gather and process natural gas and NGLs. For the six months ended June 30, 2018, the adoption of ASC 606 resulted in a decrease of $6.5 million to our natural gas and NGL sales revenues, with a corresponding decrease to gathering and processing expense, but did not affect operating income, net income or operating cash flows. Comparative information for the prior period continues to be reported under the accounting standards in effect for that period. Adoption of the new standard did not impact natural gas or NGL production volumes. For additional information regarding the new revenue recognition standard, see Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements.”

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Summary of Operating and Financial Results

In the six months ended June 30, 2018, as compared to the six months ended June 30, 2017, we:


•	Brought online 38 gross (28.7 net) wells, of which we operated 26 gross (23.7 net), all within the southern Delaware Basin;


•	Increased average daily production by 154% to 31,098 Boe/d, comprised of 78% oil;


•	Grew oil production 142% to 24,400 barrels per day, natural gas production by 257% to 21.5 MMcf/d and NGL production rose 164% to 3,120 barrels per day;


•	Increased production revenues 212% to $287.5 million;


•	Improved cash flow from operating activities to $199.8 million from $60.0 million;


•	Recorded a $13.9 million loss on commodity derivative instruments compared to a $43.6 million gain;


•	Incurred equity-based compensation expense of $78.1 million compared to $419.7 million;


•	Successfully completed the offering of $500.0 million aggregate principal amount of 5.875% Senior Notes; and


•	Repaid our outstanding borrowings on our Amended and Restated Credit Facility.

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 six months ended June 30, 2018, our production revenues were derived 94% from oil sales, 2% from natural gas sales and 4% 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 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 June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Crude Oil (per Bbl):
Average NYMEX price	$	68.07	$	48.10	$	65.55	$	49.85
Average realized price	$	60.66	$	44.84	$	60.99	$	46.67
Average realized price, including derivative settlements	$	55.82	$	46.29	$	54.79	$	46.95
Natural Gas (per Mcf):
Average NYMEX price	$	2.85	$	3.08	$	2.96	$	3.05
Average realized price ⁽¹⁾	$	1.05	$	2.56	$	1.34	$	2.53
NGLs (per Bbl):
Average realized price ⁽¹⁾	$	23.36	$	19.00	$	22.86	$	19.56

(1)

On January 1, 2018, we adopted ASC 606. As a result of adoption, natural gas and NGL realized prices for the three months ended June 30, 2018 include gathering and processing costs which reduced our realized natural gas and NGL prices by $0.56 per Mcf and $9.18 per barrel, respectively. For the six months ended June 30, 2018, natural gas and NGL realized prices were reduced by $0.55 per Mcf and $8.14 per barrel, respectively. For additional information regarding the new revenue recognition standard, see Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements.”

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, gathering and processing 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 sales of fresh water and produced water disposal services to third parties. These revenues are reflected as other operating revenues on the consolidated and combined statements of operations.

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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 production and 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 successful drilling results 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

Historically, pricing for oil, natural gas and NGLs has been volatile and unpredictable, and we expect this volatility to continue in the future. As of June 30, 2018, we had entered into derivative oil swap contracts covering periods from July 1, 2018 through December 31, 2020 for approximately 8.3 MMbls of our projected oil production at a weighted average WTI oil price of $55.82 per barrel. We also have basis differential derivative contracts between Midland, TX and Cushing, OK for the periods from July 1, 2018 through December 31, 2020 covering 9.8 MMbls at a weighted average basis differential of $(1.74) 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. Our derivative instruments 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. During the three months ended June 30, 2018, we incurred net payments of $11.9 million related to derivative agreements that settled during this time. 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.

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Results of Operations

Comparison of the three months ended June 30, 2018 versus June 30, 2017

Revenues

Oil and Natural Gas Revenues. The following table provides the components of our revenues for the three months ended June 30, 2018 and 2017, as well as each period’s respective average prices and production volumes:



	Three Months Ended June 30,
(in thousands or as indicated)	2018		2017		Change			% Change
Production revenues:
Oil sales	$	148,614	$	48,388	$	100,226		207	%
Natural gas sales	2,338		1,841		497			27	%
NGL sales	7,599		2,663		4,936			185	%
Total production revenues	$	158,551	$	52,892	$	105,659		200	%
Average realized price: ^{(1) (2)}
Oil (per Bbl)	$	60.66	$	44.84	$	15.82		35	%
Natural gas (per Mcf)	$	1.05	$	2.56	$	(1.51	)	(59	)%
NGLs (per Bbl)	$	23.36	$	19.00	$	4.36		23	%
Total (per Boe)	$	50.41	$	39.50	$	10.91		28	%
Production volumes:
Oil (MBbls)	2,450		1,079		1,371			127	%
Natural gas (MMcf)	2,220		719		1,501			209	%
NGLs (MBbls)	325		140		185			132	%
Total (MBoe)	3,145		1,339		1,806			135	%
Average daily production volume:
Oil (Bbls/d)	26,921		11,858		15,063			127	%
Natural gas (Mcf/d)	24,399		7,896		16,503			209	%
NGLs (Bbls/d)	3,575		1,540		2,035			132	%
Total (Boe/d)	34,562		14,714		19,848			135	%


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

(2)

On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of our natural gas and NGL sales revenues, with a corresponding change to our gathering and processing expense. For additional information regarding the new revenue recognition standard, see Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements.” See the table below for a breakout of the impact on our revenues and expense of adopting ASC 606:



	Three Months Ended June 30, 2018
(in thousands)	Amounts presented on statements of operations		ASC 606 Adjustments		Previous Revenue Recognition Method
Production revenues:
Oil sales	$	148,614	$	—	$	148,614
Natural gas sales	2,338		986		3,324
NGL sales	7,599		2,986		10,585
Total production revenues	$	158,551	$	3,972	$	162,523
Operating expenses:
Gathering and processing expenses	$	—	$	3,972	$	3,972

As reflected in the table above, our total production revenue for the three months ended June 30, 2018 was 200%, or $105.7 million, higher than that of the same period from 2017. The increase is primarily due to higher sales volumes, along with higher realized commodity prices during the three months ended June 30, 2018. Our aggregate production volumes in the

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three months ended June 30, 2018 were 3,145 MBoe, comprised of 78% oil, 12% natural gas and 10% NGLs. This represents an increase of 135% over aggregate production volumes of 1,339 MBoe during the three months ended June 30, 2017.

The following table shows the effects of volume and price related changes on oil, natural gas and NGL sales from the three months ended June 30, 2017 to the three months ended June 30, 2018:



(in thousands)	Oil sales		Natural gas sales			NGL sales		Total
Three months ended June 30, 2017	$	48,388	$	1,841		$	2,663	$	52,892
Changes due to:
Increase (decrease) in production volumes	61,470		3,850			3,521		68,841
Increase (decrease) in average realized prices ⁽¹⁾	38,756		(3,353		)	1,415		36,818
Three months ended June 30, 2018	$	148,614	$	2,338		$	7,599	$	158,551


(1)	The changes due to natural gas and NGL average realized prices were impacted by the adoption of ASC 606, as described above.

Operating Expenses

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



	Three Months Ended June 30,									Per Boe
(in thousands, except per Boe)	2018		2017		Change			% Change		2018		2017
Lease operating expenses	$	10,486	$	3,890	$	6,596		170	%	$	3.33	$	2.90
Gathering and processing expenses ⁽¹⁾	—		655		(655		)	(100	)%	$	—	$	0.49
Production and ad valorem taxes	9,246		3,537		5,709			161	%	$	2.94	$	2.64
Exploration	1		2		(1		)	(50	)%	$	—	$	—
Depletion, depreciation, amortization and accretion	54,915		22,311		32,604			146	%	$	17.46	$	16.66
Impairment of unproved oil and natural gas properties	—		101		(101		)	(100	)%	NM		NM
Other operating expenses	24		47		(23		)	(49	)%	$	0.01	$	0.04
General and administrative (before equity-based compensation)	8,454		7,445		1,009			14	%	$	2.69	$	5.56
Total operating expenses (before equity-based compensation)	83,126		37,988		45,138			119	%	$	26.43	$	28.37
Equity-based compensation	2,379		10,775		(8,396		)
Total operating expenses	$	85,505	$	48,763	$	36,742

(1)

On January 1, 2018, we adopted ASC 606 which changed the presentation of our natural gas and NGL sales revenues, with a corresponding change to our gathering and processing expense. See Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements” for more information, and the table in footnote 1 to the oil and natural gas revenues table, above, for a breakout of the impact on gathering and processing expense.

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 $10.5 million in the three months ended June 30, 2018, compared to $3.9 million for the same period of 2017. The increase largely relates to our increased production and well counts between periods that resulted in higher costs for equipment rental, electricity, contract labor and general maintenance and repair. Additionally, during the three months ended June 30, 2018, we incurred approximately $3.0 million of additional workover expense as compared to the same period of 2017. LOE per Boe increased 15% to $3.33 for the three months ended June 30, 2018, as compared to the same period of 2017, primarily due to the additional workover costs, which do not necessarily fluctuate in conjunction with production levels.

Gathering and Processing Expenses. Gathering and processing expenses were $0.7 million in the three months ended June 30, 2017 and were reduced to $0 in the three months ended June 30, 2018 as a result of adopting ASC 606. During the three months ended June 30, 2018, $4.0 million of gathering and processing costs that previously would have been presented as expenses were deducted from revenues. Based on the sales contracts we currently have, all gathering and processing costs are

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deducted from revenue; however, future contracts could have different terms which may require us to record gathering and processing expense. For additional information regarding the adoption of ASC 606, see Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements.”

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 161% between the three months ended June 30, 2018 and 2017, from $3.5 million in 2017 to $9.2 million in 2018. 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.

Depletion, Depreciation, Amortization and Accretion. Depletion, depreciation, amortization and accretion (“DD&A”) expense increased $32.6 million, or 146%, during the three months ended June 30, 2018 compared to the same period of 2017. The increase in DD&A expense was largely due to an increase in production, as well as an increase 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 increased 5% to $17.46 per Boe during the three months ended June 30, 2018, compared to $16.66 per Boe for the three months ended June 30, 2017. The increase in our DD&A rate was largely due to an increase in capitalized costs due to continued development activities, while the rate of increase in our reserve volumes related to those development activities was lower than the rate of capitalized costs increase.

General and Administrative and Equity-based Compensation. General and administrative expenses (“G&A”), excluding equity-based compensation, increased 14% to $8.5 million for the three months ended June 30, 2018, from $7.4 million for the same period of 2017. The increase is due to a $1.0 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support our development program and growing production levels. The number of our full-time employees increased from 52 at June 30, 2017 to 75 at June 30, 2018.

Equity-based compensation expense for the three months ended June 30, 2018 and 2017 is summarized as follows:



	Three Months Ended June 30,
(in thousands)	2018		2017		Change
Incentive unit awards	$	559	$	9,929	$	(9,370	)
Restricted stock unit awards	928		507		421
Performance stock unit awards	892		339		553
Total equity-based compensation expense	$	2,379	$	10,775	$	(8,396	)

The decrease in equity-based compensation expense for incentive unit awards is due to the modification and acceleration of the awards granted at the time of the IPO for accounting purposes in the first quarter of 2018. The remaining incentive unit award expense relates to awards not allocated at the time of the IPO. The increase in RSU and PSU awards is the result of additional grants throughout 2017 and through the first two quarters of 2018. For additional information regarding our equity-based compensation, see Note 5, Equity-based Compensation, in “Part I. Financial Information - Item 1. Financial Statements.”

Other Income and Expense

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



	Three Months Ended June 30,
(in thousands)	2018			2017			Change
Gain (loss) on commodity derivatives	$	(9,584	)	$	26,573		$	(36,157	)
Interest expense, net	(6,108		)	(432		)	(5,676		)
Other, net	10			243			(233		)
Total other income (expense)	$	(15,682	)	$	26,384		$	(42,066	)

Gain (loss) on Commodity Derivatives. Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity prices against our derivative instruments and monthly settlements, if any, of the instruments. To the extent the future commodity price outlook declines between measurement periods, we will generally have noncash mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will generally have noncash mark-to-market losses.

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The following table sets forth the components of gain (loss) on commodity derivatives for the three months ended June 30, 2018 and 2017:



	Three Months Ended June 30,
(in thousands)	2018			2017
Net cash receipts (payments) on settled derivatives	$	(11,879	)	$	1,567
Gain (loss) from the change in fair value of open derivative contracts, net	2,295			25,006
Gain (loss) on commodity derivatives	$	(9,584	)	$	26,573

Interest Expense, net. The following table summarizes our interest expense for the three months ended June 30, 2018 and 2017:



	Three Months Ended June 30,
(in thousands)	2018			2017
Amended and Restated Credit Facility ⁽¹⁾	$	1,615		$	289
Senior Notes	4,346			—
Amortization of debt issuance costs ⁽²⁾	421			143
Capitalized interest	(274		)	—
Interest expense, net	$	6,108		$	432


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


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

The increase in interest expense on the Amended and Restated Credit Facility is due to an increase in our weighted average credit facility outstanding of $129.7 million during the three months ended June 30, 2018, compared to no borrowings during the same period of 2017. During the three months ended June 30, 2018, the Amended and Restated Credit Facility had a maximum balance outstanding of $320.0 million before it was paid down with proceeds from the issuance of the Senior Notes in May 2018. Interest expense on the Senior Notes during the three months ended June 30, 2018 is a result of the issuance of the Senior Notes in May 2018.

Income tax expense (benefit)

Income tax expense decreased to $12.4 million during the three months ended June 30, 2018, from $14.3 million for the same period of 2017. The decrease is primarily due to the passage of the Tax Act, which reduced the U.S. corporate income tax rate from 35% in 2017 to 21% in 2018. This was partially offset by higher net taxable income during the three months ended June 30, 2018 compared to the same period of 2017.

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Comparison of the six months ended June 30, 2018 versus June 30, 2017

Revenues

Oil and Natural Gas Revenues. The following table provides the components of our production revenues for the six months ended June 30, 2018 and 2017, as well as each period’s respective average prices and production volumes:



	Six Months Ended June 30,
(in thousands or as indicated)	2018		2017		Change			% Change
Production revenues:
Oil sales	$	269,337	$	85,153	$	184,184		216	%
Natural gas sales	5,213		2,758		2,455			89	%
NGL sales	12,907		4,181		8,726			209	%
Total production revenues	$	287,457	$	92,092	$	195,365		212	%
Average realized price: ^{(1) (2)}
Oil (per Bbl)	$	60.99	$	46.67	$	14.32		31	%
Natural gas (per Mcf)	$	1.34	$	2.53	$	(1.19	)	(47	)%
NGLs (per Bbl)	$	22.86	$	19.56	$	3.30		17	%
Total (per Boe)	$	51.07	$	41.49	$	9.58		23	%
Production volumes:
Oil (MBbls)	4,416		1,824		2,592			142	%
Natural gas (MMcf)	3,886		1,088		2,798			257	%
NGLs (MBbls)	565		214		351			164	%
Total (MBoe)	5,629		2,220		3,409			154	%
Average daily production volume:
Oil (Bbls/d)	24,400		10,080		14,320			142	%
Natural gas (Mcf/d)	21,471		6,013		15,458			257	%
NGLs (Bbls/d)	3,120		1,181		1,939			164	%
Total (Boe/d)	31,098		12,263		18,835			154	%


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

(2)



	Six Months Ended June 30, 2018
(in thousands)	Amounts presented on statements of operations		ASC 606 Adjustments		Previous Revenue Recognition Method
Production revenues:
Oil sales	$	269,337	$	—	$	269,337
Natural gas sales	5,213		1,885		7,098
NGL sales	12,907		4,601		17,508
Total production revenues	$	287,457	$	6,486	$	293,943
Operating expenses:
Gathering and processing expenses	$	—	$	6,486	$	6,486

As reflected in the table above, our total production revenue for the first six months of 2018 was 212%, or $195.4 million, higher than that of the same period from 2017. The increase is primarily due to higher sales volumes, along with higher average realized commodity prices during the first six months of 2018. Our aggregate production volumes in the first six months of 2018 were 5,629 MBoe, comprised of 78% oil, 12% natural gas and 10% NGLs. This represents an increase of 154% over aggregate production volumes of 2,220 MBoe during the first six months of 2017.

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The following table shows the effects of volume and price related changes on oil, natural gas and NGL sales from the six months ended June 30, 2017 to the six months ended June 30, 2018:



(in thousands)	Oil sales		Natural gas sales			NGL sales		Total
Six months ended June 30, 2017	$	85,153	$	2,758		$	4,181	$	92,092
Changes due to:
Increase (decrease) in production volumes	120,942		7,080			6,862		134,884
Increase (decrease) in average realized prices ⁽¹⁾	63,242		(4,625		)	1,864		60,481
Six months ended June 30, 2018	$	269,337	$	5,213		$	12,907	$	287,457


(1)	The changes due to natural gas and NGL average realized prices were impacted by the adoption of ASC 606, as described above.

Operating Expenses

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



	Six Months Ended June 30,									Per Boe
(in thousands, except per Boe)	2018		2017		Change			% Change		2018		2017
Lease operating expenses	$	20,206	$	5,500	$	14,706		267	%	$	3.59	$	2.48
Gathering and processing expenses ⁽¹⁾	—		1,047		(1,047		)	(100	)%	$	—	$	0.47
Production and ad valorem taxes	16,920		6,177		10,743			174	%	$	3.01	$	2.78
Exploration	1		8		(7		)	(88	)%	$	—	$	—
Depletion, depreciation, amortization and accretion	102,892		36,373		66,519			183	%	$	18.28	$	16.39
Impairment of unproved oil and natural gas properties	53		108		(55		)	(51	)%	NM		NM
Other operating expenses	46		182		(136		)	(75	)%	$	0.01	$	0.08
General and administrative (before equity-based compensation)	19,093		12,032		7,061			59	%	$	3.39	$	5.42
Total operating expenses (before equity-based compensation)	159,211		61,427		97,784			159	%	$	28.28	$	27.68
Equity-based compensation	78,057		419,739		(341,682		)
Total operating expenses	$	237,268	$	481,166	$	(243,898	)

(1)

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 to $20.2 million in the first six months of 2018, compared to $5.5 million for the same period of 2017. The increase largely relates to our increased production and well counts between periods that resulted in higher costs for equipment rental, contract labor, electricity, and general maintenance and repair. Additionally, during the six months ended June 30, 2018, we incurred approximately $6.8 million of additional workover expense, as compared to the same period of 2017. LOE per Boe increased 45% to $3.59 for the six months ended June 30, 2018, primarily due to the additional workover costs, which do not necessarily fluctuate in conjunction with production levels.

Gathering and Processing Expenses. Gathering and processing expenses were $1.0 million in the first six months of 2017 and were reduced to $0 in the first six months of 2018 as a result of adopting ASC 606. During the first six months of 2018, $6.5 million of gathering and processing costs that would have previously been presented as expenses were deducted from revenues. Based on the sales contracts we currently have, all gathering and processing costs are deducted from revenue; however, future contracts could have different terms which may require us to record gathering and processing expense. For additional information regarding the adoption of ASC 606, see Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements.”

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Production and Ad Valorem Taxes. Production and ad valorem taxes increased 174% between the six months ended June 30, 2018 and 2017, from $6.2 million in 2017 to $16.9 million in 2018. 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.

Depletion, Depreciation, Amortization and Accretion. DD&A expense increased $66.5 million, or 183%, through the first six months of 2018 compared to the same period of 2017. The increase in DD&A expense was largely due to an increase in production, as well as an increase 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 increased 12% to $18.28 per Boe during the six months ended June 30, 2018, compared to $16.39 per Boe for the first six months of 2017. The increase in our DD&A rate was largely due to an increase in capitalized costs due to continued development activities, while the rate of increase in our reserve volumes related to those development activities was lower than the rate of capitalized costs increase.

General and Administrative and Equity-based Compensation. G&A, excluding equity-based compensation, increased 59% to $19.1 million for the six months ended June 30, 2018, from $12.0 million for the same period of 2017. The increase is primarily due to a $3.7 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support our development program and growing production levels, and a $2.8 million increase related to severance and other nonrecurring expenses from the first quarter of 2018. The number of our full-time employees increased from 52 at June 30, 2017 to 75 at June 30, 2018.

Equity-based compensation expense for the six months ended June 30, 2018 and 2017 is summarized as follows:



	Six Months Ended June 30,
(in thousands)	2018		2017		Change
Incentive unit awards	$	75,158	$	418,893	$	(343,735	)
Restricted stock unit awards	2,402		507		1,895
Performance stock unit awards	497		339		158
Total equity-based compensation expense	$	78,057	$	419,739	$	(341,682	)

Equity-based compensation expense for the six months ended June 30, 2018 includes (1) $71.3 million related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO and (2) the reversal of equity-based compensation expense associated with awards that were forfeited during the six months ended June 30, 2018, notably PSU awards forfeited by former executive officers. As our policy is to recognize forfeitures as they occur, previously recognized expense on unvested awards is reversed at the date of forfeiture. For the six months ended June 30, 2017, equity-based compensation expense for incentive unit awards of $419.7 million included (1) $379.0 million related to the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016, and (2) $22.2 million related to a modification in conjunction with a March 2017 separation agreement of a former executive officer. We expect to recognize additional noncash compensation expense of approximately $5.8 million over approximately 2.6 years for the incentive unit awards, $8.7 million over approximately 2.4 years for RSU awards and $9.2 million over approximately 2.4 years for the PSU awards. For additional information regarding our equity-based compensation, see Note 5, Equity-based Compensation, in “Part I. Financial Information - Item 1. Financial Statements.”

Other Income and Expense

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



	Six Months Ended June 30,
(in thousands)	2018			2017			Change
Gain (loss) on commodity derivatives	$	(13,910	)	$	43,615		$	(57,525	)
Interest expense, net	(8,839		)	(1,143		)	(7,696		)
Other, net	18			414			(396		)
Total other income (expense)	$	(22,731	)	$	42,886		$	(65,617	)

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market gains, while to the extent future commodity price outlook increases between measurement periods, we will generally have noncash mark-to-market losses.

The following table sets forth the components of gain (loss) on commodity derivatives for the six months ended June 30, 2018 and 2017:



	Six Months Ended June 30,
(in thousands)	2018			2017
Net cash receipts (payments) on settled derivatives	$	(27,358	)	$	496
Gain (loss) from the change in fair value of open derivative contracts, net	13,448			43,119
Gain (loss) on commodity derivatives	$	(13,910	)	$	43,615

Interest Expense, net. The following table summarizes our interest expense for the six months ended June 30, 2018 and 2017:



	Six Months Ended June 30,
(in thousands)	2018			2017
Amended and Restated Credit Facility ⁽¹⁾	$	4,037		$	946
Senior Notes	4,346			—
Amortization of debt issuance costs ⁽²⁾	1,021			260
Capitalized interest	(565		)	(63		)
Interest expense, net	$	8,839		$	1,143


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


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

The increase in interest expense on our Amended and Restated Credit Facility is primarily due to an increase in the weighted average outstanding balance on our credit facility of $175.3 million during the six months ended June 30, 2018, compared to $24.5 million during the same period of 2017. Interest expense on the Senior Notes during the six months ended June 30, 2018 is a result of the issuance of the Senior Notes in May 2018.

Income tax expense (benefit)

Income tax expense decreased to $22.1 million during the six months ended June 30, 2018, from $103.6 million for the same period of 2017. The decrease is primarily due to the $79.1 million recorded in the first quarter of 2017 as a result of our change in tax status as part of the corporate reorganization. Additionally, the decrease was impacted by the passage of the Tax Act which reduced the U.S. corporate income tax rate from 35% in 2017 to 21% in 2018, partially offset by higher net taxable income during the six months ended June 30, 2018 compared to the same period of 2017.

Liquidity and Capital Resources

Historically, our primary sources of liquidity were capital contributions from equity owners, including the IPO, borrowings under our credit facility and cash flows from operations. During the first six months of 2018, our primary sources of liquidity were the proceeds from the Senior Notes offering of $488.7 million, borrowings on our credit facility of $165.0 million and cash flows from operations of $199.8 million. Historically, our primary use of cash has been for the development and acquisition of oil, natural gas and NGL properties, as well as for the development of water sourcing and disposal infrastructure. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate level returns will be highly dependent on the capital resources available to us.

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Capital Expenditures

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



	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2018		2017		2018		2017
Acquisitions
Proved properties	$	—	$	—	$	—	$	—
Unproved properties ⁽¹⁾	3,808		25,709		11,326		48,519
Development costs	176,178		148,906		383,793		240,187
Infrastructure costs	4,028		9,821		7,770		18,192
Exploration costs	1		2		1		8
Total oil and gas capital expenditures	$	184,015	$	184,438	$	402,890	$	306,906


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

For the six months ended June 30, 2018 and 2017, our capital expenditures have been focused on the development of our properties in the southern Delaware Basin. As of June 30, 2018, we had approximately 90,400 gross (79,300 net) acres.

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



	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Gross wells
Operated	15	14	26	21
Non-operated	4	2	12	2
	19	16	38	23
Net wells
Operated	13.7	13.8	23.7	20.7
Non-operated	1.6	0.5	5.0	0.5
	15.3	14.3	28.7	21.2

At June 30, 2018, we were in the process of drilling three gross (3.0 net) wells and had eight gross (7.8 net) wells waiting on completion, including three gross (2.9 net) wells that were in process of being completed.

2018 Capital Budget

Our 2018 capital budget for development of oil and gas properties and infrastructure is as follows:



(in millions)
Drilling and completion	$	650.0	—	$	680.0
Water infrastructure	18.0		—	22.0
Total	$	668.0	—	$	702.0

Our 2018 capital budget excludes potential leasehold and/or surface acreage additions. Based on our 2018 capital budget, we expect to bring online 44 to 46 gross 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 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

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expirations. Furthermore, we may be required to remove some portion of our reserves currently booked as proved undeveloped 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 2018 capital program. 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 future drilling program. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

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 June 30, 2018, we had working capital of $26.6 million, an increase of $140.0 million compared to a working capital deficit of $113.4 million at December 31, 2017. The increase is primarily the result of a $126.0 million increase in our cash balance, which increased primarily due to the net proceeds from the Senior Notes offering in May 2018, net of repayment of our then outstanding balance on our credit facility and underwriter and other offering fees. Additionally, we experienced a net increase in current derivative assets of $14.8 million, primarily related to the increase in fair value of our basis swaps expected to settle over the next 12 months, and an increase of $11.3 million primarily related to increased JIB AR. These increases were partially offset by an increase of $13.5 million in current liabilities associated with ongoing development activities.

We may incur additional working capital deficits in the future due to future increases in liabilities related to our drilling program or further decreases in the value of our current commodity derivatives. 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 $135.5 million and $9.5 million at June 30, 2018 and December 31, 2017, respectively. We expect that our cash flows from operating activities, access to capital markets and availability under our credit facility will be sufficient to fund our working capital needs. We expect that our timing of receivables and payables, pace of development, production volumes, commodity and differentials to NYMEX 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:



	Six Months Ended June 30,
(in thousands)	2018			2017
Net cash provided by operating activities	$	199,814		$	60,005
Net cash used in investing activities	$	(405,902	)	$	(249,636	)
Net cash provided by financing activities	$	332,057		$	264,900

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

The $139.8 million increase in the first six months of 2018 compared to 2017 primarily resulted from a $195.3 million increase in revenues, which resulted from a 154% increase in volumes and a 23% increase in the average price received per Boe. This was partially offset by $24.3 million of higher cash operating costs primarily due to increased production, and $7.1 million of increased cash G&A costs due to additional personnel, severance and other nonrecurring expenses.

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

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During the first six months of 2018, net cash flow used in investing activities was $405.9 million, which included investments in developing our acreage of $393.0 million and leasehold and acquisition costs of $11.1 million. In the first six months of 2017, net cash used for investing activities of $249.6 million included $195.2 million and $53.0 million for the development and acquisition of oil and natural gas properties, respectively.

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

Net cash provided by financing activities during the first six months of 2018 was primarily due to $488.7 million of net proceeds from the Senior Notes offering, which was partially offset by a net repayment on our credit facility of $155.0 million. Net cash provided by financing activities in the first six months of 2017 was primarily due to $401.6 million of net proceeds from the sale of common stock in the IPO and a net repayment of $132.0 million on our credit facility.

Senior Secured Revolving Credit Facility

At December 31, 2017, the Amended and Restated Credit Facility had a borrowing base of $425.0 million, with $155.0 million outstanding under the credit facility, and $270.0 million in unused borrowing capacity. In March 2018, we entered into Amendment No. 2 to the Amended and Restated Credit Facility which extended the maturity date of the Amended and Restated Credit Facility to March 21, 2023, increased the borrowing base to $540.0 million, increased the hedging limits and lowered the pricing grid.

In April 2018, and in connection with the issuance of the Senior Notes, the lenders of the Amended and Restated Credit Facility agreed to waive a provision that would require a borrowing base reduction as a result of the Senior Notes. As a result, the borrowing base of the Amended and Restated Credit Facility continued to be $540.0 million as of June 30, 2018. We also voluntarily elected to reduce the elected commitments to $475.0 million, effective as of the closing of the Senior Notes offering. Additionally, a portion of the proceeds from the Senior Notes were used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received. In August 2018, our borrowing base was increased to $825.0 million and we increased our elected commitments to $540.0 million. As of the date of this filing, the Company has nothing outstanding and $540.0 million available under the Amended and Restated Credit Facility.

The amount available to be borrowed under our Amended and Restated Credit Facility is subject to a borrowing base that is subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year by the lenders at their sole discretion. Additionally, at our option, we may request up to two additional redeterminations per year, to be effective on or about January 1 and July 1, 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.

At June 30, 2018, we were obligated to pay a commitment fee on unused amounts of our Amended and Restated Credit Facility of 0.375% to 0.50% per year on the unused portion of the elected commitments, depending on the relative amount of the loan outstanding in relation to the elected commitments. 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:

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

As of June 30, 2018, we were in compliance with all financial covenants.

Under Amendment No. 3 of our Amended and Restated Credit Facility, we are permitted to hedge up to 85% of forecasted production for up to 36 months in the future, and up to the greater of 75% of our proved reserves and 60% of our reasonably anticipated forecasted production for 37 to 60 months in the future, provided that no hedges have a term beyond five years.

Contractual Obligations

A summary of our contractual obligations as of June 30, 2018 is provided in the following table:



	Remainder		Payments Due by Period for the Year Ending December 31,
(in thousands)	of 2018		2019		2020		2021		2022		2023		Thereafter		Total
Senior notes—principal	$	—	$	—	$	—	$	—	$	—	$	—	$	500,000	$	500,000
Senior notes—interest ⁽¹⁾	14,808		29,375		29,375		29,375		29,375		29,375		68,408		230,091
Operating leases ⁽²⁾	522		1,503		1,526		1,547		1,553		1,584		7,378		15,613
Service and purchase contracts ⁽³⁾	7,241		6,753		1,285		750		—		—		—		16,029
Rig contracts ⁽⁴⁾	11,318		4,393		—		—		—		—		—		15,711
Frac fleet contracts ⁽⁵⁾	21,600		—		—		—		—		—		—		21,600
Total	$	55,489	$	42,024	$	32,186	$	31,672	$	30,928	$	30,959	$	575,786	$	799,044


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


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


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


(4)	Relates to five drilling rig contracts as of June 30, 2018. If we were to terminate these contracts at June 30, 2018, we would be required to pay early termination penalties of approximately $5.1 million.

(5)

Relates to three frac fleets under contract at June 30, 2018. The majority of the contracts allow for reassignment of the frac fleets to another operator 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 $3.2 million as of June 30, 2018.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of June 30, 2018. Please read Note 10, Commitments and Contingencies, in “Part I. Financial Information - Item 1. Financial Statements” for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

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 2017 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for impairment of oil and natural gas properties, oil, natural gas and NGL reserve quantities and standardized measure of discounted future net cash flows, derivative instruments, and income taxes. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to our consolidated 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.

Recent Accounting Pronouncements

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


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with “Item 7A. Qualitative and Quantitative Disclosures About Market Risk” contained in our 2017 Form 10-K.

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

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

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has 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 NGL production depend on numerous factors beyond our control.

To reduce our exposure to changes in the prices of commodities we have entered into, and may in the future enter into, commodity derivative instruments for a portion of our oil production for the years 2018 through 2020. The agreements entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil production over a fixed period of time. Our commodity derivative instruments are recorded at fair value and thus changes to the future commodity prices will have an impact on net income. During the six months ended June 30, 2018 we recorded a loss on derivatives of $13.9 million, compared to a gain of $43.6 million for the same period from 2017.

The fair value of our derivative instruments is determined based on valuation models. We did not change our valuation method for our derivative instruments during the six months ended June 30, 2018. The following table reconciles the changes that occurred in the fair values of our derivative instruments from December 31, 2017 to June 30, 2018:



	Commodity Derivative Instruments
(in thousands)	Net Assets (Liabilities)
Fair value of open contracts at December 31, 2017	$	(52,851	)
Change in fair value of open contracts	(13,910		)
Net cash payments on settled derivatives	27,358
Fair value of open contracts at June 30, 2018	$	(39,403	)

The following table sets forth the hypothetical impact on the fair value of our net oil derivative liability of $39.4 million as of June 30, 2018, using an average increase or decrease of 10% to the commodity prices:



	Change to Prices
(in thousands)	10% Increase		10% Decrease
Increase (decrease) to net oil derivative liability as of June 30, 2018	$	48,088	$	(48,088	)

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

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

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

Interest Rate Risk

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

As of June 30, 2018, we had no significant investments other than cash and cash equivalents and therefore we were not exposed to material interest rate risk on investments.

Prior to paying down the outstanding balance on our Amended and Restated Credit Facility to $0 in May 2018, we were exposed to changes in interest rates as a result of our Amended and Restated Credit Facility. As of June 30, 2018, we had $500.0 million aggregate principal of fixed-rate long-term debt outstanding, net of unamortized debt issuance costs, with a fixed interest rate of 5.875%. Although near term changes in interest rates may impact the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss. Therefore, we have no exposure to fluctuating interest rates as of June 30, 2018.

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


Item 4.	Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2018. 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 June 30, 2018 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, 2017 and Item 8.01, Other Events, in our Current Report on Form 8-K filed with the SEC on April 23, 2018. 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, 2017 and our Current Report on Form 8-K filed with the SEC on April 23, 2018.


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
4.1		Indenture, dated as of May 8, 2018, by and among Jagged Peak Energy LLC, Jagged Peak Energy Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed with the SEC on May 8, 2018).
4.2		Registration Rights Agreement, dated as of May 8, 2018, by and among Jagged Peak Energy Inc., Jagged Peak Energy LLC and J.P. Morgan Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed with the SEC on May 8, 2018).
10.1		Limited Consent and Agreement, dated as of April 20, 2018, by and among Jagged Peak Energy LLC, as borrower, Jagged Peak Energy Inc., as guarantor, 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 (incorporated by reference to Exhibit 10.4 to the Company’s Form 10-Q filed with the SEC on May 10, 2018).
*10.2		Amendment No. 3 to Amended and Restated Credit Agreement, dated as of June 15, 2018, 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:	August 9, 2018	By:	/s/ JAMES J. KLECKNER
			Name:	James J. Kleckner
			Title:	Chief Executive Officer and President

Date:	August 9, 2018	By:	/s/ ROBERT W. HOWARD
			Name:	Robert W. Howard
			Title:	Executive Vice President, Chief Financial Officer

Date:	August 9, 2018	By:	/s/ SHONN D. STAHLECKER
			Name:	Shonn D. Stahlecker
			Title:	Controller

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