10-Q 1 a2018q210-q.htm 10-Q Document

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 
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-37995
Jagged Peak Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware
(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.
Large accelerated filer o
 
Accelerated filer o
 
Non-accelerated filer x
(Do not check if a smaller reporting company)
 
Smaller reporting company o
Emerging growth company x
 
 
 
 
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.




TABLE OF CONTENTS


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




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.

1


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

2


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.

3



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.

4


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.

5


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
 
 
 
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.

6


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.

7

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.


8

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.


9

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.


10

JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)

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



11

JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)

 
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.


12

JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)

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.


13

JAGGED PEAK ENERGY INC.
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


14

JAGGED PEAK ENERGY INC.
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

15

JAGGED PEAK ENERGY INC.
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

16

JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)

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

17

JAGGED PEAK ENERGY INC.
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.


18

JAGGED PEAK ENERGY INC.
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

19

JAGGED PEAK ENERGY INC.
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.


20

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

21

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.


22

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.


23


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.”


24


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.

25



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.


26


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

27


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

28


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