Document
Table of Contents


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 March 31, 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 213,110,757 shares of common stock outstanding at May 4, 2018.



Table of Contents


TABLE OF CONTENTS


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



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

Table of Contents


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 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 spud and 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;
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

Table of Contents


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

Table of Contents



PART I—FINANCIAL INFORMATION

Item 1.
Financial Statements
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
 
March 31,
 
December 31,
 
2018
 
2017
ASSETS
 

 
 

CURRENT ASSETS
 

 
 

Cash and cash equivalents
$
3,205

 
$
9,523

Accounts receivable
55,833

 
50,734

Derivative instruments
14,602

 

Other current assets
1,984

 
806

Total current assets
75,624

 
61,063

PROPERTY AND EQUIPMENT
 

 
 

Oil and natural gas properties, successful efforts method
1,414,364

 
1,195,831

Accumulated depletion
(214,002
)
 
(166,592
)
Total oil and gas properties, net
1,200,362

 
1,029,239

Other property and equipment, net
9,489

 
9,708

Total property and equipment, net
1,209,851

 
1,038,947

OTHER NONCURRENT ASSETS
 

 
 

Unamortized debt issuance costs
4,196

 
3,273

Derivative instruments
2,138

 
26

Other assets
121

 
119

Total noncurrent assets
6,455

 
3,418

TOTAL ASSETS
$
1,291,930

 
$
1,103,428

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

CURRENT LIABILITIES
 

 
 

Accounts payable
$
22,639

 
$
382

Accrued liabilities
137,113

 
132,311

Derivative instruments
48,003

 
41,782

Total current liabilities
207,755

 
174,475

LONG-TERM LIABILITIES
 

 
 

Long-term debt
265,000

 
155,000

Derivative instruments
10,435

 
11,095

Asset retirement obligations
1,052

 
811

Deferred income taxes
67,587

 
57,943

Other long-term liabilities
4,681

 
4,759

Total long-term liabilities
348,755

 
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, 213,110,757 shares issued at March 31, 2018; 212,930,655 shares issued at December 31, 2017
2,131

 
2,129

Additional paid-in capital
849,150

 
773,674

Accumulated deficit
(115,861
)
 
(76,458
)
Total stockholders’ equity
735,420

 
699,345

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
1,291,930

 
$
1,103,428

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

4

Table of Contents


JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands, except per share amounts)
 
Three Months Ended March 31,
 
2018
 
2017
REVENUES
 
 
 

Oil sales
$
120,723

 
$
36,765

Natural gas sales
2,875

 
917

NGL sales
5,308

 
1,518

Other operating revenues
147

 
188

Total revenues
129,053

 
39,388

OPERATING EXPENSES
 

 
 

Lease operating expenses
9,720

 
1,610

Gathering and processing expenses

 
392

Production and ad valorem taxes
7,674

 
2,640

Exploration

 
6

Depletion, depreciation, amortization and accretion
47,977

 
14,062

Impairment of unproved oil and natural gas properties
53

 
7

General and administrative expenses (including equity-based compensation of $75,678 and $408,964 for the three months ended March 31, 2018 and 2017, respectively)
86,317

 
413,551

Other operating expenses
22

 
135

Total operating expenses
151,763

 
432,403

INCOME (LOSS) FROM OPERATIONS
(22,710
)
 
(393,015
)
OTHER INCOME (EXPENSE)
 

 
 

Gain (loss) on commodity derivatives
(4,326
)
 
17,042

Interest expense, net
(2,731
)
 
(711
)
Other, net
8

 
171

Total other income (expense)
(7,049
)
 
16,502

INCOME (LOSS) BEFORE INCOME TAX
(29,759
)
 
(376,513
)
Income tax expense (benefit)
9,644

 
89,368

NET INCOME (LOSS)
(39,403
)
 
(465,881
)
Less: Net loss attributable to Jagged Peak Energy LLC (predecessor)

 
(375,476
)
NET INCOME (LOSS) ATTRIBUTABLE TO JAGGED PEAK ENERGY INC. STOCKHOLDERS
$
(39,403
)
 
$
(90,405
)
 
 
 
 
Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share:
 
 
 
Basic
$
(0.18
)
 
$
(0.42
)
Diluted
$
(0.18
)
 
$
(0.42
)
 
 
 
 
Weighted-average common shares outstanding:
 
 
 
Basic
213,003

 
212,938

Diluted
213,003

 
212,938

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

5

Table of Contents


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
180

 
2

 
(202
)
 

 
(200
)
Equity-based compensation

 

 
75,678

 

 
75,678

Net income (loss)

 

 

 
(39,403
)
 
(39,403
)
BALANCE AT MARCH 31, 2018
213,111

 
$
2,131

 
$
849,150

 
$
(115,861
)
 
$
735,420


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

6

Table of Contents


JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
 
Three Months Ended March 31,
 
2018
 
2017
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income (loss)
$
(39,403
)
 
$
(465,881
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:


 


Depletion, depreciation, amortization and accretion expense
47,977

 
14,062

Impairment of unproved oil and natural gas properties
53

 
7

Amortization of debt issuance costs
600

 
117

Deferred income taxes
9,644

 
89,368

Equity-based compensation
75,678

 
408,964

(Gain) loss on commodity derivatives
4,326

 
(17,042
)
Net cash receipts (payments) on settled derivatives
(15,479
)
 
(1,071
)
Other
(78
)
 
(39
)
Change in operating assets and liabilities:
 

 
 

Accounts receivable and other current assets
(5,351
)
 
(6,325
)
Accounts payable and accrued liabilities
2,275

 
(459
)
Net cash provided by operating activities
80,242

 
21,701

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Leasehold and acquisition costs
(7,585
)
 
(25,628
)
Development of oil and natural gas properties
(185,982
)
 
(74,293
)
Other capital expenditures
(1,270
)
 
(763
)
Net cash used in investing activities
(194,837
)
 
(100,684
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Proceeds from issuance of common stock in initial public offering, net of underwriting fees

 
401,625

Proceeds from credit facility
110,000

 
10,000

Repayment of credit facility

 
(142,000
)
Debt issuance costs
(1,523
)
 
(1,000
)
Costs relating to initial public offering

 
(2,560
)
Employee tax withholding for settlement of equity compensation awards
(200
)
 

Net cash provided by financing activities
108,277

 
266,065

NET CHANGE IN CASH AND CASH EQUIVALENTS
(6,318
)
 
187,082

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
9,523

 
11,727

CASH AND CASH EQUIVALENTS, END OF PERIOD
$
3,205

 
$
198,809

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
 
 
 
Interest paid, net of capitalized interest
$
1,947

 
$
697

Cash paid for income taxes

 

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
 
 
 
Accrued capital expenditures
$
130,171

 
$
58,518

Asset retirement obligations
230

 
40

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
 
 
 
Accrued offering costs
$

 
$
657

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

7

Table of Contents
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 Company’s 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 6, Equity-based Compensation, and Note 8, Income Taxes, respectively.

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


8

Table of Contents
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

Table of Contents
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 March 31, 2018 and December 31, 2017, accounts receivable was comprised of the following:
(in thousands)
March 31, 2018
 
December 31, 2017
Oil and gas sales
$
48,297

 
$
42,869

Joint interest
7,079

 
7,860

Other
457

 
5

Total accounts receivable
$
55,833

 
$
50,734


At March 31, 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)
March 31, 2018
 
December 31, 2017
Proved oil and natural gas properties
$
1,227,233

 
$
1,012,321

Unproved oil and natural gas properties
187,131

 
183,510

Total oil and natural gas properties
1,414,364

 
1,195,831

Less: Accumulated depletion
(214,002
)
 
(166,592
)
Total oil and natural gas properties, net
$
1,200,362

 
$
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 March 31, 2018 and 2017, the Company recorded depletion for oil and natural gas properties of $47.4 million and $13.7 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated and combined statements of operations.


10

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

Accrued Liabilities

The components of accrued liabilities are shown below:
(in thousands)
March 31, 2018
 
December 31, 2017
Accrued capital expenditures
$
107,366

 
$
102,956

Accrued accounts payable
8,608

 
8,488

Royalties payable
8,799

 
6,105

Other current liabilities
12,340

 
14,762

Total accrued liabilities
$
137,113

 
$
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 March 31, 2018
(in thousands)
Amounts presented on statement of operations
 
ASC 606 Adjustments
 
Previous Revenue Recognition Method
Revenues
 
 
 
 
 
Oil sales
$
120,723

 
$

 
$
120,723

Natural gas sales
2,875

 
899

 
3,774

NGL sales
5,308

 
1,615

 
6,923

Other operating revenues
147

 

 
147

Total revenues
$
129,053

 
$
2,514

 
$
131,567

 
 
 
 
 
 
Operating expenses
 
 
 
 
 
Gathering and processing expenses
$

 
$
2,514

 
$
2,514

 
 
 
 
 
 
Net income (loss)
$
(39,403
)
 
$

 
$
(39,403
)

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.


11

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

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 Company will adopt the new standard on January 1, 2019. The Company is in process of evaluating the impact of this new standard, which includes an analysis of existing contracts, including drilling rig and frac fleet contracts, office leases and certain field equipment. The Company is also evaluating the effect of ASU 2016-02 on its current accounting policies, disclosures and controls. 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 update does not apply to leases of mineral rights to explore for or use oil and natural gas. 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. The Company intends to elect this transition provision. The Company continues to monitor relevant industry guidance regarding the implementation of ASU 2016-02 and will adjust its implementation strategies as necessary.

Note 3—Derivative Instruments

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

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

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.


12

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

The following table summarizes the Company’s derivative contracts as of March 31, 2018:
Contract Period
 
Volumes
(Bbls)
 
Wtd Avg Price
($/Bbl)
Oil Swaps: (1)
 

 

Second quarter 2018
 
1,412,000

 
$
52.69

Third quarter 2018
 
1,481,200

 
$
53.14

Fourth quarter 2018
 
1,467,400

 
$
53.45

Total 2018
 
4,360,600

 
$
53.10

Year ending December 31, 2019
 
2,372,500

 
$
51.89

Oil Basis Swaps: (2)
 
 
 
 
Second quarter 2018
 
1,410,500

 
$
(0.97
)
Third quarter 2018
 
1,426,000

 
$
(0.97
)
Fourth quarter 2018
 
1,426,000

 
$
(0.97
)
Total 2018
 
4,262,500

 
$
(0.97
)
Year ending December 31, 2019
 
2,920,000

 
$
(1.10
)
(1)
The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price.
(2)
The oil basis swap differential price is between 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. The changes in fair value of these instruments are recognized through earnings as other income or expense rather than deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity price indices. The ultimate gain or loss upon settlement of these transactions is recognized in earnings as other income or expense. Cash settlements of the Company’s derivative contracts are included in cash flows from operating activities in the Company’s statements of cash flows.

Subsequent to March 31, 2018, the Company entered into the following additional derivative contracts:
Contract Period
 
Volumes
(Bbls)
 
Wtd Avg Price
($/Bbl)
Oil Swaps: (1)
 
 
 
 
Third quarter 2018
 
138,000

 
$
65.21

Fourth quarter 2018
 
138,000

 
$
65.21

Total 2018
 
276,000

 
$
65.21

Year ending December 31, 2019
 
1,277,500

 
$
60.25

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

The Company recognized the following gains (losses) and net cash receipts (payments) in earnings for the periods indicated:
 
Three Months Ended March 31,
(in thousands)
2018
 
2017
Gain (loss) on derivative instruments, net
$
(4,326
)
 
$
17,042

Net cash receipts (payments) on settled derivatives
$
(15,479
)
 
$
(1,071
)

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.


13

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

The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of March 31, 2018 and December 31, 2017 (in thousands):
As of March 31, 2018:
 
Balance Sheet Location
 
Gross amounts presented on the balance sheet
 
Netting adjustments not offset on the balance sheet
 
Net amounts
Assets
 
 
 
 
 
 
 
 
Commodity contracts
 
Current assets - derivative instruments
 
$
14,602

 
$
(13,132
)
 
$
1,470

Commodity contracts
 
Noncurrent assets - derivative instruments
 
2,138

 
(2,138
)
 

Total assets
 
 
 
$
16,740

 
$
(15,270
)
 
$
1,470

Liabilities
 
 
 
 
 
 
 
 
Commodity contracts
 
Current liabilities - derivative instruments
 
$
48,003

 
$
(13,132
)
 
$
34,871

Commodity contracts
 
Noncurrent liabilities - derivative instruments
 
10,435

 
(2,138
)
 
8,297

Total liabilities
 
 
 
$
58,438

 
$
(15,270
)
 
$
43,168

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 is represented by 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 March 31, 2018, the Company had commodity derivative contracts with five counterparties, all of which were lenders under the Company’s Amended and Restated Credit Facility (as defined in Note 5, 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—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.

14

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


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

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

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

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

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

Assets and liabilities measured on a recurring basis

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

The following table is a listing of the Company’s assets and liabilities that were measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017:
 
Level 2
(in thousands)
March 31, 2018
 
December 31, 2017
Assets from commodity derivative contracts
$
16,740

 
$
26

Liabilities due to commodity derivative contracts
$
58,438

 
$
52,877


Assets and liabilities measured on a nonrecurring basis

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

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

15

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

factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs. No impairments were recorded on proved properties during the three months ended March 31, 2018 and 2017.

Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Company uses a market approach, and takes into account future development plans, remaining lease term, drilling results, and reservoir performance. The Company recorded impairment expense on unproved oil and gas properties of $53 thousand and $7 thousand for the three months ended March 31, 2018 and 2017, respectively. These impairments resulted from expirations of certain undeveloped leases.

The inception value of the Company’s asset retirement obligations is 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.

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

Fair Value of Other Financial Instruments

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

Note 5—Debt

Senior Secured Revolving Credit Facility

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, at December 31, 2017. 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, increased the aggregate commitment to $1.5 billion 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 alternative base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50%, and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative 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 borrowing base. The commitment fee paid by the Company is between 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base.

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


16

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

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 March 31, 2018, the Company was in compliance with its financial covenants.

As of March 31, 2018, there was $265.0 million outstanding under the Amended and Restated Credit Facility. The weighted-average interest rate as of March 31, 2018 was 3.51%.

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 continues to be $540.0 million. The Company also voluntarily elected to reduce the elected commitment 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. As of the date of this filing, the Company has no borrowings outstanding, and $475.0 million available under the Amended and Restated Credit Facility.

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. The Senior Notes resulted in net proceeds to the Company, after deducting the initial purchasers’ discount and offering expenses, of approximately $489.3 million. A portion of such proceeds 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. 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.

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 are unconditionally guaranteed on a senior unsecured basis by Jagged Peak, and may be guaranteed by certain future subsidiaries of Jagged Peak.

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 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 any accrued but unpaid interest as of the date of repurchase.

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.

17

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


Note 6—Equity-based Compensation

Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated and combined statements of operations, for each type of equity-based compensation award was as follows for the periods indicated:
 
Three Months Ended March 31,
(in thousands)
2018
 
2017
Incentive unit awards
$
74,599

 
$
408,964

Restricted stock unit awards
1,319

 

Performance stock unit awards
(395
)
 

Restricted stock unit awards issued to nonemployee directors
155

 

Total equity-based compensation expense
$
75,678

 
$
408,964


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 three months ended March 31, 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 during the three months ended March 31, 2018, notably performance stock unit (“PSU”) awards forfeited by former executive officers. As the Company’s policy is to recognize forfeitures as they occur, previously recognized expense on unvested awards is reversed at the date of forfeiture. For the three months ended March 31, 2017, equity-based compensation expense for incentive unit awards of $409.0 million included (1) $379.0 million related to the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016, and (2) $22.2 million related to a modification in conjunction with a March 2017 separation agreement of a former executive officer. Through March 31, 2017, the Company did not issue any awards under its long-term incentive plan; as such, there is no equity-based compensation through that date other than the incentive unit awards.

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 are 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 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.


18

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

The following table summarizes the Company’s incentive unit award, restricted stock unit (“RSU”) award and PSU award activity for the three months ended March 31, 2018:
 
Incentive Units (2)
 
Restricted Stock Units
 
Performance Stock Units
Unvested at December 31, 2017
7,755,745

 
582,973

 
398,566

Awards Granted (1)
293,118

 
427,060

 
534,758

Vested
(2,789,511
)
 
(195,655
)
 

Forfeited
(72,563
)
 
(91,970
)
 
(234,596
)
Unvested at March 31, 2018
5,186,789

 
722,408

 
698,728

(1) Weighted average grant-date fair value
$
13.65

 
$
12.52

 
$
14.69

(2)
Included in the unvested incentive units at March 31, 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.

The following table reflects the future equity-based compensation expense to be recorded for each type of award that was outstanding at March 31, 2018:
 
Incentive Units
 
Restricted Stock Units
 
Performance Stock Units
Compensation costs remaining at March 31, 2018 (in millions)
$
4.9

 
$
8.0

 
$
9.4

Weighted average remaining period at March 31, 2018 (in years)
2.8

 
2.6

 
2.6


At March 31, 2018, there were 210,766 unallocated incentive unit awards 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 7—Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net earnings by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested RSUs and PSUs if including such potential shares of common stock units is dilutive. The PSUs included in the calculation of diluted weighted average shares outstanding 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 three months ended March 31, 2017, the Company’s EPS calculation includes only the net loss for the period subsequent to the corporate reorganization and IPO, and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017 to March 31, 2017. Through March 31, 2017, the Company did not issue any shares under its long-term incentive plan; as such, there are no potentially dilutive shares as of that date.


19

Table of Contents
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
 
From January 27, 2017, to
(in thousands, except per share amounts)
March 31, 2018
 
March 31, 2017
Net income (loss) attributable to Jagged Peak Energy Inc. stockholders
$
(39,403
)
 
$
(90,405
)
 
 
 
 
Basic weighted average shares outstanding
213,003

 
212,938

Dilutive restricted stock units

 

Dilutive performance stock units

 

Diluted weighted average shares outstanding
213,003

 
212,938

 
 
 
 
Net income (loss) per common share:
 
 
 
Basic
$
(0.18
)
 
$
(0.42
)
Diluted
$
(0.18
)
 
$
(0.42
)

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
 
From January 27, 2017, to
(in thousands)
March 31, 2018
 
March 31, 2017
Number of antidilutive units: (1)
 
 
 
Antidilutive restricted stock units
624

 

Antidilutive performance stock units
361

 

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

Note 8—Income Taxes

Income tax expense was as follows for the periods indicated:
 
Three Months Ended March 31,
(in thousands)
2018
 
2017
Income tax expense
$
9,644

 
$
89,368

Effective tax rate
(32.4
)%
 
(23.7
)%

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 three months ended March 31, 2017, is a $79.1 million 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 March 31, 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 months ended March 31, 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

20

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

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 March 31, 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 9—Asset Retirement Obligations

The following table summarizes the changes in the carrying amount of the asset retirement obligations for the three months ended March 31, 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
195

Liability settlements and disposals

Revisions of estimated liabilities
35

Accretion
25

Asset retirement obligations at March 31, 2018
1,184

Less current portion of asset retirement obligations
(132
)
Long-term asset retirement obligations
$
1,052


Note 10—Commitments and Contingencies

Commitments

There were no material changes in commitments during the first three 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 such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental Matters

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

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

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.

21

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


The following table summarizes fees paid to Oryx, Phoenix and Trident for the periods indicated:
 
Three Months Ended March 31,
(in thousands)
2018
 
2017
Oryx via 3rd party shipper (1)
$
4,734

 
$
1,419

Oryx (2)
$
215

 
$
349

Phoenix (3)
$
109

 
$
85

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 March 31, 2018 and December 31, 2017, the Company had outstanding payables to these related parties of $1.8 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.

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 March 31, 2018, our acreage position was approximately 77,700 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 three months of 2017, our realized oil price for the first three months of 2018 increased 24% to $61.39 per barrel, our realized natural gas price declined 30% to $1.73 per Mcf, and our realized price for NGLs increased by 8% to $22.17 per barrel between these same periods. The realized natural gas and NGL prices during the first

22

Table of Contents


three months of 2018 were 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 Drilling Activity

During the three months ended March 31, 2018, we completed 11 gross (10.0 net) operated wells. Our average daily production has grown from 9,785 Boe/d during the first three months of 2017 to 27,596 Boe/d for the same period of 2018. In the three months ended March 31, 2018, we spent $211.4 million for drilling and completing wells and on water infrastructure costs. This compares to $99.7 million that we spent in the three months ended March 31, 2017 for drilling, completion and infrastructure.

Equity-based Compensation

During the three months ended March 31, 2018, we recognized equity-based compensation expense of $75.7 million, which included $71.3 million related to a modification of service requirements for incentive unit awards. During the three months ended March 31, 2017, we recognized equity-based compensation of $409.0 million which included $379.0 million related to incentive unit awards that vested at the time of the IPO. Please refer to Note 6, 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 three months ended March 31, 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 8, 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, reduced 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 eliminated 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 costs incurred to gather and process natural gas and NGLs. For the three months ended March 31, 2018, the adoption of ASC 606 resulted in a decrease of $2.5 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.”

Summary of Operating and Financial Results Comparing the Three Months Ended March 31, 2018 and 2017

Placed on production 19 gross (13.4 net) wells, of which we operated 11 gross (10.0 net), all within the southern Delaware Basin;
Increased average daily production by 182% to 27,596 Boe/d, comprised of 79% oil;
Grew oil production 164% to 21,850 barrels per day, natural gas production by 350% to 18.5 MMcf/d and NGL production rose 225% to 2,660 barrels per day;
Production revenues rose 229% to $128.9 million;

23

Table of Contents


Improved cash flow from operating activities to $80.2 million from $21.7 million for the same period of 2017;
Recorded a $4.3 million loss on commodity derivative instruments compared to a $17.0 million gain from the same period in 2017;
Incurred equity-based compensation expense of $75.7 million compared to $409.0 million from the same period in 2017; and
Increased our borrowing base from $425.0 million to $540.0 million.

In addition, in May 2018, we completed the offering of $500.0 million aggregate principal amount of 5.875% Senior Notes, due on May 1, 2026, repaid our outstanding borrowings on our credit facility and elected to lower the commitment amount of our Amended and Restated Credit Facility to $475.0 million.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. For the three months ended March 31, 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 March 31,
 
2018
 
2017
Crude Oil (per Bbl):
 

 
 

Average NYMEX price
$
62.91

 
$
51.62

Realized price, before the effects of derivative settlements
$
61.39

 
$
49.33

Realized price, after the effects of derivative settlements
$
53.52

 
$
47.89

Natural Gas (per Mcf):
 

 
 

Average NYMEX price
$
3.08

 
$
3.02

Realized price (1)
$
1.73

 
$
2.48

NGLs (per Bbl):
 

 
 

Realized price (1)
$
22.17

 
$
20.61

(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 March 31, 2018 include gathering and processing costs which reduced our realized natural gas and NGL prices by $0.54 per Mcf and $6.74 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.

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 decline. Accordingly, we plan to maintain our focus on adding reserves through drilling, as well as acquisitions. Our

24

Table of Contents


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 March 31, 2018, we had entered into derivative oil swap contracts covering periods from April 1, 2018 through December 31, 2019 for approximately 6.7 MMbls of our projected oil production at a weighted average WTI oil price of $52.67 per barrel. We also have basis differential derivative contracts between Midland, TX and Cushing, OK for the periods from April 1, 2018 through December 31, 2019 covering 7.2 MMbls at a weighted average basis differential of $(1.03) 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 March 31, 2018, we incurred net payments of $15.5 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.

Results of Operations

Comparison of the three months ended March 31, 2018 versus March 31, 2017

Revenues

Oil and Natural Gas Revenues.    The following table provides the components of our production revenues for the three months ended March 31, 2018 and 2017, as well as each period’s respective average prices and production volumes:
 
Three Months Ended March 31,
 
 
 
 
(in thousands or as indicated)
2018
 
2017
 
Change
 
% Change
Production revenues:
 

 
 

 
 

 
 

Oil sales
$
120,723

 
$
36,765

 
$
83,958

 
228
 %
Natural gas sales
2,875

 
917

 
1,958

 
214
 %
NGL sales
5,308

 
1,518

 
3,790

 
250
 %
Total production revenues
$
128,906

 
$
39,200

 
$
89,706

 
229
 %
Average sales price: (1) (2)
 
 
 
 
 
 
 
Oil (per Bbl)
$
61.39

 
$
49.33

 
$
12.06

 
24
 %
Natural gas (per Mcf)
$
1.73

 
$
2.48

 
$
(0.75
)
 
(30
)%
NGLs (per Bbl)
$
22.17

 
$
20.61

 
$
1.56

 
8
 %
Total (per Boe)
$
51.90

 
$
44.52

 
$
7.38

 
17
 %
Production volumes:
 
 
 
 
 
 
 
Oil (MBbls)
1,967

 
745

 
1,222

 
164
 %
Natural gas (MMcf)
1,666

 
370

 
1,296

 
350
 %
NGLs (MBbls)
239

 
74

 
165

 
223
 %
Total (MBoe)
2,484

 
881

 
1,603

 
182
 %
Average daily production volume:
 
 
 
 
 
 
 
Oil (Bbls/d)
21,850

 
8,281

 
13,569

 
164
 %
Natural gas (Mcf/d)
18,510

 
4,109

 
14,401

 
350
 %
NGLs (Bbls/d)
2,660

 
819

 
1,841

 
225
 %
Total (Boe/d)
27,596

 
9,785

 
17,811

 
182
 %
(1)
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

25

Table of Contents


“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 March 31, 2018
(in thousands)
Amounts presented on statement of operations
 
ASC 606 Adjustments
 
Previous Revenue Recognition Method
Production revenues:
 
 
 
 
 
Oil sales
$
120,723

 
$

 
$
120,723

Natural gas sales
2,875

 
899

 
3,774

NGL sales
5,308

 
1,615

 
6,923

Total production revenues
$
128,906

 
$
2,514

 
$
131,420

Operating expenses
 
 
 
 
 
Gathering and processing expenses
$

 
$
2,514

 
$
2,514

(2)
Average prices shown in the table do not include settlements of commodity derivative transactions.

As reflected in the table above, our total production revenue for the first three months of 2018 was 229%, or $89.7 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 first three months of 2018. Our aggregate production volumes in the first three months of 2018 were 2,484 MBoe, comprised of 79% oil, 11% natural gas and 10% NGLs. This represents an increase of 182% over aggregate production volumes of 881 MBoe during the first three months of 2017.

Increased production volumes accounted for an approximate $66.9 million increase in year-over-year production revenues, while an increase in our total equivalent sales price accounted for an approximate $22.8 million increase in production revenues between periods. The total equivalent sales price was impacted by the adoption of ASC 606, as described above. Production increases are largely related to our active drilling program over the last 12 months.

During the three months ended March 31, 2018, oil revenues increased 228%, or $84.0 million, due to a 164% increase in production volumes and a 24% increase in the average realized price when compared to the same period from the prior year. Natural gas revenues increased 214% to $2.9 million during the three months ended March 31, 2018 from $0.9 million during the three months ended March 31, 2017. The increase is attributable to a 350% increase in volumes, partially offset by a 30% decrease in the average sales price, which was impacted by the adoption of ASC 606. During the first three months of 2018, NGL revenues increased 250%, or $3.8 million, due to a 223% increase in volumes and an 8% increase in the average realized price, which was also impacted by the adoption of ASC 606.

Other Operating Revenues. Other operating revenues relate to sales of fresh water and water disposal services to third parties. During the first three months of 2018 and 2017, we recognized other operating revenue of $0.1 million and $0.2 million, respectively. The change is due to fluctuating sales of our excess fresh water and water disposal capacity between periods.


26

Table of Contents


Operating Expenses

The following table summarizes our operating expenses for the periods indicated:
 
Three Months Ended March 31,
 
 
 
 
 
Per Boe
(in thousands, except per Boe)
2018
 
2017
 
Change
 
% Change
 
2018
 
2017
Lease operating expenses
$
9,720

 
$
1,610

 
$
8,110

 
504
 %
 
$
3.91

 
$
1.83

Gathering and processing expenses (1)

 
392

 
(392
)
 
(100
)%
 
$

 
$
0.45

Production and ad valorem taxes
7,674

 
2,640

 
5,034

 
191
 %
 
$
3.09

 
$
3.00

Exploration

 
6

 
(6
)
 
(100
)%
 
$

 
$
0.01

Depletion, depreciation, amortization and accretion
47,977

 
14,062

 
33,915

 
241
 %
 
$
19.31

 
$
15.97

Impairment of unproved oil and natural gas properties
53

 
7

 
46

 
657
 %
 
NM

 
NM

Other operating expenses
22

 
135

 
(113
)
 
(84
)%
 
$
0.01

 
$
0.15

General and administrative (before equity-based compensation)
10,639

 
4,587

 
6,052

 
132
 %
 
$
4.28

 
$
5.21

Total operating expenses (before equity-based compensation)
76,085

 
23,439

 
52,646

 
225
 %
 
$
30.63

 
$
26.62

Equity-based compensation
75,678

 
408,964

 
(333,286
)
 
 
 
 
 
 
Total operating expenses
$
151,763

 
$
432,403

 
$
(280,640
)
 
 
 
 
 
 
(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 $9.7 million in the first three months of 2018, compared to $1.6 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 contract labor, general maintenance and repair, equipment rental and electricity. Additionally, during the three months ended March 31, 2018, we incurred approximately $3.8 million of additional workover expense, as compared to the same period of 2017. LOE per Boe increased 114% to $3.91 for the three months ended March 31, 2018, primarily due to the additional workover costs, which do not necessarily fluctuate in conjunction with production levels.

Gathering and Processing Expenses.    Gathering and processing expenses were $0.4 million in the first three months of 2017 and were reduced to $0 in the first three months of 2018 as a result of adopting ASC 606. During the first three months of 2018, $2.5 million of gathering and processing costs that would have previously been presented as expenses were deducted from revenues. Based on the contracts we currently have, all gathering and processing costs are deducted from revenue; however, future contracts could have different terms which may require us to record gathering and processing expense. For additional information regarding the adoption of ASC 606, see Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements.”

Production and Ad Valorem Taxes.    Production and ad valorem taxes increased 191% between the three months ended March 31, 2018 and 2017, from $2.6 million in 2017 to $7.7 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.

Exploration.    The $6 thousand of exploration expense in the three months ended March 31, 2017 is due to delay rentals on certain unproved properties.

Depletion, Depreciation, Amortization and Accretion.    Depletion, depreciation, amortization and accretion (“DD&A”) expense increased $33.9 million, or 241%, through the first three months of 2018 compared to the same period of 2017. The increase in DD&A expense was largely due to an increase in production, as well as an increase in our DD&A rate. Our DD&A rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The DD&A rate per Boe increased 21% to $19.31 per Boe, compared to $15.97 per Boe in the first three months

27

Table of Contents


of 2017. The increase in our DD&A rate was largely due to an increase in capitalized costs due to continued development activities, while the rate of increase in our reserve volumes related to those development activities was lower than the rate of capitalized costs increase.

Impairment of Unproved Oil and Natural Gas Properties.    During the first three months of 2018, we incurred $0.1 million of impairment costs related to the expiration of certain leases on unproved properties. During the same period in 2017, we recorded $7 thousand of impairment expense related to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties in either period of 2018 or 2017.

Other Operating Expenses.    During the first three months of 2018, we incurred $22 thousand of other operating expenses, which represented a decrease of $0.1 million from the first three months of 2017. Other operating expenses in both periods related to costs associated with selling fresh water and water disposal services.

General and Administrative and Equity-based Compensation.    General and administrative expenses (“G&A”), excluding equity-based compensation, increased 132% to $10.6 million for the three months ended March 31, 2018, from $4.6 million for the same period of 2017. The increase is due to a $2.8 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the continued growth of our capital expenditure program and production levels, and a $2.8 million increase related to severance and other nonrecurring expenses. The number of our full-time employees increased from 41 at March 31, 2017 to 58 at March 31, 2018.

Equity-based compensation expense for the three months ended March 31, 2018 and 2017 is summarized as follows:
 
Three Months Ended March 31,
 
 
(in thousands)
2018
 
2017
 
Change
Incentive unit awards
$
74,599

 
$
408,964

 
$
(334,365
)
Restricted stock unit awards
1,474

 

 
1,474

Performance stock unit awards
(395
)
 

 
(395
)
Total equity-based compensation expense
$
75,678

 
$
408,964

 
$
(333,286
)

Equity-based compensation expense for the three months ended March 31, 2018 includes (1) $71.3 million related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO and (2) the reversal of equity-based compensation expense associated with awards that were forfeited during the three months ended March 31, 2018, notably PSU awards forfeited by former executive officers. As our policy is to recognize forfeitures as they occur, previously recognized expense on unvested awards is reversed at the date of forfeiture. For the three months ended March 31, 2017, equity-based compensation expense for incentive unit awards of $409.0 million included (1) $379.0 million related to the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016, and (2) $22.2 million related to a modification in conjunction with a March 2017 separation agreement of a former executive officer. Through March 31, 2017, we did not issue any awards under our long-term incentive plan; as such, there is no equity-based compensation through that date other than the incentive unit awards. We expect to recognize additional noncash compensation expense of approximately $4.9 million over approximately 2.8 years for the incentive unit awards, $8.0 million over approximately 2.6 years for RSU awards and $9.4 million over approximately 2.6 years for the PSU awards. For additional information regarding our equity-based compensation, see Note 6, Equity-based Compensation, in “Part I. Financial Information - Item 1. Financial Statements.”

Other Income and Expense

The following table summarizes our other income and expenses for the periods indicated:
 
Three Months Ended March 31,
 
 
(in thousands)
2018
 
2017
 
Change
Gain (loss) on commodity derivatives
$
(4,326
)
 
$
17,042

 
$
(21,368
)
Interest expense, net
(2,731
)
 
(711
)
 
(2,020
)
Other, net
8

 
171

 
(163
)
Total other income (expense)
$
(7,049
)
 
$
16,502

 
$
(23,551
)

Gain (loss) on Commodity Derivatives.    Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity prices against our derivative instruments and monthly settlements, if any, of the instruments. To

28

Table of Contents


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

The following table sets forth the net gain (loss) from settlements and changes in the fair value of our derivative contracts, as well as the net cash receipts (payments) on settlements for the three months ended March 31, 2018 and 2017:
 
Three Months Ended March 31,
(in thousands)
2018
 
2017
Gain (loss) on derivative instruments, net
$
(4,326
)
 
$
17,042

Net cash receipts (payments) on settled derivatives
$
(15,479
)
 
$
(1,071
)

Interest Expense, net.    Interest expense relates to interest paid on the outstanding balance of the Amended and Restated Credit Facility, commitment fees paid on the unused borrowing base and amortization of debt issuance costs, net of capitalized interest. The terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. During the first three months of 2018 and 2017, we recorded $2.7 million and $0.7 million, respectively, of interest expense, net of capitalized interest, related to borrowings on our credit facility. The increase in interest paid is primarily because our average outstanding debt balance during the first three months of 2018 was $240.0 million compared to $47.3 million for the same period of 2017. Our maximum debt outstanding during the first three months of 2018 was $265.0 million in March, which we repaid in full in May 2018 with a portion of the proceeds from the Senior Notes offering. During the first three months of 2017, our maximum debt outstanding was $142.0 million in January, which we repaid in full in February 2017 with a portion of the proceeds from the IPO.

Income tax expense (benefit)

Income tax expense decreased to $9.6 million during the three months ended March 31, 2018, from $89.4 million for the same period of 2017. The decrease is due to the $79.1 million recorded in the first quarter of 2017 as a result of our change in tax status as part of the corporate reorganization. Additionally, the decrease was impacted by the passage of the Tax Act which reduced the U.S. corporate income tax rate from 35% to 21%, partially offset by higher net taxable income during the three months ended March 31, 2018 compared to the same period of 2017.

Liquidity and Capital Resources

Historically, our predecessor’s primary sources of liquidity were capital contributions from equity owners, including the IPO, borrowings under our predecessor’s credit facility and cash flows from operations. During the first three months of 2018, our primary sources of liquidity were the borrowings on our credit facility of $110.0 million and cash flows from operations of $80.2 million. Historically, our predecessor’s and our primary use of cash has been for the development and acquisition of oil, natural gas and NGL properties, as well as for development of water sourcing and disposal infrastructure. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate level returns will be highly dependent on the capital resources available to us.

Capital Expenditures

Capital expenditures for oil and gas acquisitions, exploration, development and infrastructure activities are summarized below:
 
Three Months Ended March 31,
(in thousands)
2018
 
2017
Acquisitions
 
 
 
Proved properties
$

 
$

Unproved properties (1)
7,518

 
22,810

Development costs
207,615

 
91,281

Infrastructure costs
3,742

 
8,371

Exploration costs

 
6

Total oil and gas capital expenditures
$
218,875

 
$
122,468


29

Table of Contents


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

For the three months ended March 31, 2018 and 2017, our capital expenditures have been focused on the development of our properties in the southern Delaware Basin. As of March 31, 2018, we had approximately 88,000 gross (77,700 net) acres.

The following table reflects wells that began producing in the periods indicated:
 
Three Months Ended March 31,
 
2018
 
2017
Gross wells
 
 
 
Operated
11

 
7

Non-operated
8

 

 
19

 
7

Net wells
 
 
 
Operated
10.0

 
6.9

Non-operated
3.4

 

 
13.4

 
6.9


At March 31, 2018, we were in the process of drilling four gross (4.0 net) wells and had thirteen gross (12.9 net) wells waiting on completion, including eight gross (8.0 net) wells that were in process of being completed.

2018 Capital Budget

Our 2018 capital budget for development of oil and gas properties and infrastructure is as follows:
(in millions)
 
 
 
Drilling and completion (1)
$
540.0

$
590.0

Water infrastructure
20.0

25.0

Total
$
560.0

$
615.0

(1)
The 2018 drilling and completion budget includes $5 - $10 million budgeted for 3D seismic and other data initiatives.

Our 2018 capital budget excludes potential leasehold and/or surface acreage additions. Based on our 2018 capital budget, we expect to spud approximately 40 to 45 gross operated wells, and place on production 42 to 46 gross operated wells. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

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

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations, additional borrowing capacity under our credit facility and the proceeds from our Senior Notes offering in April 2018 to execute our remaining 2018 capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. If we require additional capital funding for capital expenditures, acquisitions or other reasons, we may seek such capital through borrowings under our credit facility, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program. In addition, we may not be able to complete

30

Table of Contents


acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

Working Capital

Our working capital, which we define as current assets minus current liabilities, fluctuates primarily as a result of our realized commodity prices, increases or decreases in our production volumes, changes in receivables and payables related to our operating and development of oil and natural gas activities, changes in our hedging activities and changes in our cash and cash equivalents. At March 31, 2018, we had a working capital deficit of $132.1 million, an increase of $18.7 million compared to a working capital deficit of $113.4 million at December 31, 2017. The increased deficit is primarily the result of $27.5 million in current liabilities associated with ongoing development activities and a decrease of $6.3 million in our cash balance related to our timing of receivables and payables.  These factors were partially offset by a net increase in current derivative assets of $8.4 million, primarily related to expected settlements of our basis swaps over the next 12 months, a decrease in payroll liabilities of $3.2 million related to payroll timing and an increase of $2.7 million in revenue receivable, net of royalties payable, associated with the timing of our growing revenues.

We may incur additional working capital deficits in the future due to future increases in liabilities related to our drilling program or further decreases in the value of our current commodity derivatives. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled approximately $3.2 million and $9.5 million at March 31, 2018 and December 31, 2017, respectively. We expect that our cash flows from operating activities, access to capital markets and availability under our credit facility will be sufficient to fund our working capital needs. We expect that our timing of receivables and payables, pace of development, production volumes, commodity and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

Cash Flows

The following table summarizes our cash flows for the periods indicated:
 
Three Months Ended March 31,
(in thousands)
2018
 
2017
Net cash provided by operating activities
$
80,242

 
$
21,701

Net cash used in investing activities
$
(194,837
)
 
$
(100,684
)
Net cash provided by financing activities
$
108,277

 
$
266,065


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

The $58.5 million increase in the first three months of 2018 compared to 2017 primarily resulted from a $89.7 million increase in revenues, which resulted from a 182% increase in volumes and a 17% increase in the average price received per Boe. This was partially offset by $12.6 million of higher cash operating costs primarily due to increased production, and $6.1 million of increased cash G&A costs due to additional personnel, severance and other nonrecurring expenses.

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

During the first three months of 2018, net cash flow used in investing activities was $194.8 million, which included investments in developing our acreage of $186.0 million and leasehold and acquisition costs of $7.6 million. In the first three months of 2017, net cash used for investing activities of $100.7 million included $74.3 million and $25.6 million for the development and acquisition of oil and natural gas properties, respectively.

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

Net cash provided by financing activities during the first three months of 2018 was primarily due to $110.0 million of borrowings on our credit facility. Net cash provided by financing activities in the first three months of 2017 was primarily due to $401.6 million of net proceeds from the sale of common stock in the IPO and $10.0 million of borrowings on our credit facility, which was partially offset by a repayment on our credit facility of $142.0 million after the IPO.


31

Table of Contents


Senior Secured Revolving Credit Facility

At December 31, 2017, the Amended and Restated Credit Facility had a borrowing base of $425.0 million, with $155.0 million outstanding under the credit facility, and $270.0 million in unused borrowing capacity. In March 2018, we entered into Amendment No. 2 to the Amended and Restated Credit Facility which extended the maturity date of the Amended and Restated Credit Facility to March 21, 2023, increased the aggregate commitment to $1.5 billion, increased the borrowing base to $540.0 million, increased the hedging limits and lowered the pricing grid.

In April 2018, and in connection with the issuance of the Senior Notes, the lenders of the Amended and Restated Credit Facility agreed to waive a provision that would require a borrowing base reduction as a result of the Senior Notes. As a result, the borrowing base of the Amended and Restated Credit Facility continues to be $540.0 million. We also voluntarily elected to reduce the elected commitment 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. As of the date of this filing, the Company has nothing outstanding, and $475.0 million available under the Amended and Restated Credit Facility.

The amount available to be borrowed under our Amended and Restated Credit Facility is subject to a borrowing base that is subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year by the lenders at their sole discretion. Additionally, at our option, we may request up to two additional redeterminations per year, to be effective on or about January 1 and July 1, respectively. The borrowing base depends on, among other things, the volumes of our proved reserves, estimated cash flows from those reserves, our commodity hedge positions and any other outstanding debt. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, we could be required to immediately repay a portion of the debt outstanding under our credit facility.

At March 31, 2018, we were obligated to pay a commitment fee on unused amounts of our Amended and Restated Credit Facility of 0.375% to 0.50% per year on the unused portion of the borrowing base, depending on the relative amount of the loan outstanding in relation to the borrowing base. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

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

incur additional indebtedness;
incur liens;
make investments;
make loans to others;
merge or consolidate with another entity;
sell assets;
make certain payments;
enter into transactions with affiliates;
hedge interest rates; and
engage in certain other transactions without the prior consent of the lenders.

The Amended and Restated Credit Facility contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Facility, include requirements to comply with the following financial ratios:
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 March 31, 2018, we were in compliance with all financial covenants.

Under our Amended and Restated Credit Facility, we are permitted to hedge up to 85% of forecasted production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 60% of our reasonably anticipated forecasted production for 25 to 60 months in the future, provided that no hedges have a term beyond five years.


32

Table of Contents


Contractual Obligations

We have various contractual obligations in the normal course of our operations, including long-term debt, operating leases, service and purchase contracts, drilling rig contracts and frac fleet contracts. Since December 31, 2017, the changes in our contractual obligations are not material, other than our long-term debt, which increased by $110.0 million. See Note 5, Debt, in “Part I. Financial Information - Item 1. Financial Statements” for additional information regarding our long-term debt during the three months ended March 31, 2018

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of March 31, 2018. Please read Note 10, Commitments and Contingencies, in “Part I. Financial Information - Item 1. Financial Statements” for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

Critical Accounting Policies and Estimates

Our management makes a number of significant estimates, assumptions and judgments in the preparation of our financial statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2017 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for impairment of oil and natural gas properties, oil, natural gas and NGL reserve quantities and standardized measure of discounted future net cash flows, derivative instruments, and income taxes. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to our consolidated and combined financial statements contained in this Quarterly Report on Form 10-Q. The application of our critical accounting policies may require management to make judgments and estimates about the amounts reflected in the consolidated and combined financial statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.

Recent Accounting Pronouncements

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

Item 3.
Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on numerous factors beyond our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

The following table shows how hypothetical changes in the realized prices we receive for our commodity sales would have impacted revenue for the three months ended March 31, 2018:
 
 
 
Sensitivity Analysis
(in thousands)
Revenue
 
% of Total
 
Change in Realized Prices
 
Impact on Revenue
Oil
$
120,723

 
94%
 
+ / - $1.00 per barrel
 
+ / -
$
1,967

Natural gas
2,875

 
2%
 
+ / - $0.10 per Mcf
 
+ / -
$
167

NGL
5,308

 
4%
 
+ / - $1.00 per barrel
 
+ / -
$
239

Total (1)
$
128,906

 
100%
 
 
 
 
 

33

Table of Contents


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

Due to this volatility, we use commodity derivative instruments such as swaps and basis swaps to hedge price risk associated with a portion of our oil production. In the future, we may use commodity derivatives to hedge a portion of our natural gas or NGL production. These hedging instruments will allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. This provides increased certainty of cash flows for funding our 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.

Under our Amended and Restated Credit Facility, we are permitted to hedge up to 85% of forecasted production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 60% of our reasonably anticipated forecasted production for 25 to 60 months in the future, provided that no hedges have a term beyond five years.

At March 31, 2018, we had a net liability position of $41.7 million related to our derivatives in place for the years 2018 through 2019. The following table shows how hypothetical changes in the respective prices for our open derivative positions as of March 31, 2018 would impact our net oil derivative liability:
 
 
Change to Prices
(in thousands)
 
10% Increase
 
10% Decrease
Increase (decrease) to net oil derivative liability as of March 31, 2018
 
$
38,399

 
$
(38,399
)

See Note 3, Derivative Instruments, and Note 4, Fair Value Measurements, in “Part I. Financial Information - Item 1. Financial Statements” for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.

Counterparty and Customer Credit Risk

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

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

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

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Amended and Restated Credit Facility. At March 31, 2018, we had $265.0 million of debt outstanding, all of which was under our Amended and Restated Credit Facility, with a weighted average interest rate of 3.51%. If interest rates were to increase or decrease 1% as of March 31, 2018, assuming no change in the amount outstanding, the impact on interest expense in the assumed weighted average interest rate would be approximately $2.7 million per year. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. For additional information regarding our debt instruments, refer to Note 5, Debt, in “Part I. Financial Information - Item 1. Financial Statements.”

Item 4.
Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2018. Our disclosure controls and procedures are designed to

34

Table of Contents


provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2018 at the reasonable assurance level. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures.

Changes in Internal Control over Financial Reporting

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

35

Table of Contents




PART II—OTHER INFORMATION

Item 1.
Legal Proceedings

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

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

Item 1A.
Risk Factors

Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the information in Part I, Item 1A, Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017 and Item 8.01, Other Events, in our Current Report on Form 8-K filed with the SEC on April 23, 2018. There have been no material changes to our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2017 and our Current Report on Form 8-K filed with the SEC on April 23, 2018.

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

Recent sales of unregistered securities

None.

Purchases of equity securities by the issuer and affiliated purchasers

The following table summarizes the repurchase of our common stock during the three months ended March 31, 2018:
Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
January 1, 2018 - January 31, 2018
 

 
$

 

 

February 1, 2018 - February 28, 2018
 
15,553

 
$
12.85

 

 

March 1, 2018 - March 31, 2018
 

 
$

 

 

Total
 
15,553

 
$
12.85