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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the quarterly period ended September 30, 2019 
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-37995
JPE_LOGO2.JPG
Jagged Peak Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
 
 
81-3943703
(State or other jurisdiction of
incorporation or organization)
 
 
 
(IRS Employer
Identification Number)
1401 Lawrence Street, Suite 1800
 
 
 
 
Denver,
Colorado
 
 
 
80202
(Address of principal executive offices)
 
 
 
(Zip Code)
(720) 215-3700
(Registrant’s telephone number, including area code)

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐  No ☑

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Ticker Symbol
 
Name of each exchange on which registered
Common stock, par value $0.01 per share
 
JAG
 
New York Stock Exchange

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



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42



GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

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

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

Boe/d.    One Boe per day.

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

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

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

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

MBoe.    One thousand Boe.

Mcf.    One thousand cubic feet of natural gas.

Mcf/d.    One Mcf per day.

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

MMcf.    One million cubic feet of natural gas.

MMcf/d.    One MMcf per day.

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

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

NYMEX.    The New York Mercantile Exchange.

Proved properties.    Properties with proved reserves.

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

Unproved properties.    Lease acreage with no proved reserves.

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

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

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

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

1

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

Forward-looking statements include statements about:
•
our business strategy;
•
our reserves;
•
our drilling prospects, inventories, projects and programs;
•
our intention to replace the reserves we produce through drilling and property acquisitions;
•
our financial strategy, liquidity and capital required for our drilling program, including our assessment of the sufficiency of our liquidity to fund our capital program and the amount and allocation of our capital program in 2019;
•
our expected noncash compensation expenses;
•
our expected pricing and realized oil, natural gas and NGL prices;
•
the timing and amount of our future production of oil, natural gas and NGLs, including our ability to satisfy minimum gross volume commitments under certain marketing agreements;
•
our future drilling plans;
•
government regulations and our ability to obtain permits and governmental approvals;
•
our pending legal or environmental matters;
•
our marketing of oil, natural gas and NGLs;
•
our leasehold or business acquisitions;
•
our costs of developing our properties, including our capital budget;
•
our hedging strategy and results;
•
general economic conditions;
•
uncertainty regarding our future operating results;
•
our pending merger with a wholly owned subsidiary of Parsley Energy, Inc. and the expected timing of the consummation of the merger; and
•
our plans, objectives, expectations and intentions contained in this quarterly report that are not historical.

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

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

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

2


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

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

3


PART I—FINANCIAL INFORMATION

Item 1.
Financial Statements
JAGGED PEAK ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
 
September 30,
 
December 31,
 
2019
 
2018
ASSETS
 

 
 

CURRENT ASSETS
 

 
 

Cash and cash equivalents
$
10,603

 
$
35,229

Accounts receivable
62,062

 
61,186

Derivative instruments
48,006

 
103,092

Prepaid and other current assets
3,158

 
1,627

Total current assets
123,829

 
201,134

PROPERTY AND EQUIPMENT
 

 
 

Oil and natural gas properties, successful efforts method
2,377,765

 
1,905,498

Accumulated depletion
(569,733
)
 
(386,883
)
Total oil and gas properties, net
1,808,032

 
1,518,615

Other property and equipment, net
10,155

 
11,670

Total property and equipment, net
1,818,187

 
1,530,285

OTHER NONCURRENT ASSETS
 

 
 

Operating lease right-of-use assets
47,489

 
—

Derivative instruments
13,961

 
31,899

Other assets
3,279

 
3,823

Total noncurrent assets
64,729

 
35,722

TOTAL ASSETS
$
2,006,745

 
$
1,767,141

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

CURRENT LIABILITIES
 

 
 

Accounts payable
$
23,531

 
$
34,762

Accrued liabilities
136,855

 
130,012

Operating lease liabilities
36,263

 
—

Derivative instruments
27,738

 
23,208

Total current liabilities
224,387

 
187,982

LONG-TERM LIABILITIES
 

 
 

Long-term debt
705,269

 
489,239

Derivative instruments
4,659

 
11,162

Asset retirement obligations
2,609

 
1,946

Deferred income taxes
118,432

 
124,418

Operating lease liabilities
15,519

 
—

Other long-term liabilities
—

 
4,444

Total long-term liabilities
846,488

 
631,209

Commitments and contingencies


 


STOCKHOLDERS’ EQUITY
 

 
 

Preferred stock, $0.01 par value; 50,000,000 shares authorized, none issued
—

 
—

Common stock, $0.01 par value; 1,000,000,000 shares authorized, 213,404,153 shares issued at September 30, 2019; 213,187,780 shares issued at December 31, 2018
2,134

 
2,132

Additional paid-in capital
867,159

 
856,818

Retained earnings
66,577

 
89,000

Total stockholders’ equity
935,870

 
947,950

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
2,006,745

 
$
1,767,141

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

4

JAGGED PEAK ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands, except per share amounts)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
REVENUES
 
 
 
 
 
 
 
Oil sales
$
147,710

 
$
141,598

 
$
416,824

 
$
410,935

Natural gas sales
727

 
2,552

 
904

 
7,765

NGL sales
1,628

 
10,814

 
8,680

 
23,721

Other operating revenues
—

 
414

 
9

 
686

Total revenues
150,065

 
155,378

 
426,417

 
443,107

OPERATING EXPENSES
 
 
 
 
 
 
 
Lease operating expenses
17,554

 
11,184

 
46,758

 
31,390

Production and ad valorem taxes
11,263

 
9,517

 
32,100

 
26,437

Exploration
3

 
23

 
3

 
24

Depletion, depreciation, amortization and accretion
66,069

 
57,660

 
186,365

 
160,552

Impairment of unproved oil and natural gas properties
31,817

 
—

 
32,763

 
53

General and administrative expenses (including equity-based compensation of $4,098 and $2,614 for the three months ended September 30, 2019 and 2018, respectively, and $11,025 and $80,671 for the nine months ended September 30, 2019 and 2018, respectively)
13,669

 
12,321

 
40,141

 
109,471

Other operating expenses
—

 
19

 
3,206

 
65

Total operating expenses
140,375

 
90,724

 
341,336

 
327,992

INCOME (LOSS) FROM OPERATIONS
9,690

 
64,654

 
85,081

 
115,115

OTHER INCOME (EXPENSE)
 
 
 
 
 
 
 
Gain (loss) on commodity derivatives
39,421

 
(96,516
)
 
(85,702
)
 
(110,426
)
Interest expense, net
(9,974
)
 
(8,256
)
 
(27,683
)
 
(17,095
)
Gain on sale of oil and natural gas properties
—

 
6,225

 
—

 
6,225

Other, net
18

 
12

 
(105
)
 
30

Total other income (expense)
29,465

 
(98,535
)
 
(113,490
)
 
(121,266
)
INCOME (LOSS) BEFORE INCOME TAX
39,155

 
(33,881
)
 
(28,409
)
 
(6,151
)
Income tax expense (benefit)
8,597

 
(7,315
)
 
(5,986
)
 
14,737

NET INCOME (LOSS)
$
30,558

 
$
(26,566
)
 
$
(22,423
)
 
$
(20,888
)
 
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
Basic
$
0.14

 
$
(0.12
)
 
$
(0.11
)
 
$
(0.10
)
Diluted
$
0.14

 
$
(0.12
)
 
$
(0.11
)
 
$
(0.10
)
 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
213,403

 
213,180

 
213,349

 
213,109

Diluted
213,700

 
213,180

 
213,349

 
213,109

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

5

JAGGED PEAK ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(in thousands)
 
Common Stock
 
Additional Paid-in Capital
 
Retained Earnings (Accumulated Deficit)
 
Total Stockholders' Equity
 
Shares
 
Amount
 
 
 
BALANCE AT DECEMBER 31, 2018
213,188

 
$
2,132

 
$
856,818

 
$
89,000

 
$
947,950

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes
167

 
2

 
(281
)
 
—

 
(279
)
Equity-based compensation
—

 
—

 
2,934

 
—

 
2,934

Net income (loss)
—

 
—

 
—

 
(94,888
)
 
(94,888
)
BALANCE AT MARCH 31, 2019
213,355

 
2,134

 
859,471

 
(5,888
)
 
855,717

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes
39

 
—

 
(376
)
 
—

 
(376
)
Equity-based compensation
—

 
—

 
3,993

 
—

 
3,993

Net income (loss)
—

 
—

 
—

 
41,907

 
41,907

BALANCE AT JUNE 30, 2019
213,394

 
2,134

 
863,088

 
36,019

 
901,241

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes
10

 
—

 
(27
)
 
—

 
(27
)
Equity-based compensation
—

 
—

 
4,098

 
—

 
4,098

Net income (loss)
—

 
—

 
—

 
30,558

 
30,558

BALANCE AT SEPTEMBER 30, 2019
213,404

 
$
2,134

 
$
867,159

 
$
66,577

 
$
935,870

 
 
 
 
 
 
 
 
 
 
BALANCE AT DECEMBER 31, 2017
212,931

 
$
2,129

 
$
773,674

 
$
(76,458
)
 
$
699,345

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes
180

 
2

 
(202
)
 
—

 
(200
)
Equity-based compensation
—

 
—

 
75,678

 
—

 
75,678

Net income (loss)
—

 
—

 
—

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

 
2,131

 
849,150

 
(115,861
)
 
735,420

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes
68

 
1

 
—

 
—

 
1

Equity-based compensation
—

 
—

 
2,379

 
—

 
2,379

Net income (loss)
—

 
—

 
—

 
45,081

 
45,081

BALANCE AT JUNE 30, 2018
213,179

 
2,132

 
851,529

 
(70,780
)
 
782,881

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes
2

 
—

 
—

 
—

 
—

Equity-based compensation
—

 
—

 
2,614

 
—

 
2,614

Net income (loss)
—

 
—

 
—

 
(26,566
)
 
(26,566
)
BALANCE AT SEPTEMBER 30, 2018
213,181

 
$
2,132

 
$
854,143

 
$
(97,346
)
 
$
758,929

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

6

JAGGED PEAK ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
 
Nine Months Ended September 30,
 
2019
 
2018
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income (loss)
$
(22,423
)
 
$
(20,888
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:


 


Depletion, depreciation, amortization and accretion expense
186,365

 
160,552

Impairment of unproved oil and natural gas properties
32,763

 
53

Amortization of debt issuance costs
1,770

 
1,753

Deferred income taxes
(5,986
)
 
14,737

Equity-based compensation
11,025

 
80,671

(Gain) loss on commodity derivatives
85,702

 
110,426

Net cash receipts (payments) on settled derivatives
(14,651
)
 
(33,705
)
(Gain) on sale of oil and natural gas properties
—

 
(6,225
)
Other
(98
)
 
(234
)
Change in operating assets and liabilities:
 

 
 

Accounts receivable and other current assets
(2,407
)
 
(29,854
)
Accounts payable and accrued liabilities
641

 
40,461

Net cash provided by operating activities
272,701

 
317,747

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Leasehold and acquisition costs
(32,931
)
 
(18,854
)
Development of oil and natural gas properties
(477,681
)
 
(551,059
)
Other capital expenditures
(837
)
 
(3,245
)
Proceeds from sale of oil and natural gas properties
—

 
8,377

Net cash used in investing activities
(511,449
)
 
(564,781
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Proceeds from credit facility
215,000

 
165,000

Repayment of credit facility
—

 
(320,000
)
Proceeds from senior notes
—

 
500,000

Debt issuance costs
(197
)
 
(13,350
)
Employee tax withholding for settlement of equity compensation awards
(681
)
 
(200
)
Net cash provided by financing activities
214,122

 
331,450

NET CHANGE IN CASH AND CASH EQUIVALENTS
(24,626
)
 
84,416

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
35,229

 
9,523

CASH AND CASH EQUIVALENTS, END OF PERIOD
$
10,603

 
$
93,939

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
 
 
 
Interest paid, net of capitalized interest
$
18,200

 
$
4,009

Cash paid for income taxes
—

 
—

Cash paid for operating lease liabilities included in cash flows from operating activities
1,123

 
—

Cash paid for operating lease liabilities included in cash flows from investing activities
26,918

 
—

SUPPLEMENTAL DISCLOSURE OF NONCASH OPERATING ACTIVITIES
 
 
 
Lease liabilities arising from obtaining right-of-use assets
$
73,413

 
$
—

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
 
 
 
Accrued capital expenditures
$
102,275

 
$
100,780

Asset retirement obligations
1,619

 
567

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

7
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

Note 1—Organization, Operations and Basis of Presentation

Organization and Operations

Jagged Peak Energy Inc. (either individually or together with its subsidiaries, as the context requires, “Jagged Peak” or the “Company”) is an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves in the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin of West Texas.

Jagged Peak is a Delaware corporation formed in September 2016, as a wholly owned subsidiary of Jagged Peak Energy LLC (“JPE LLC”), a Delaware limited liability company formed in April 2013. JPE LLC was formed by an affiliate of Quantum Energy Partners (“Quantum”) and former members of Jagged Peak’s management team. Jagged Peak was formed to become the holding company of JPE LLC in connection with Jagged Peak’s initial public offering (the “IPO”). Additional background on the Company, its IPO and details of the ownership of the Company are available in the Company's Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”).

Basis of Presentation

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

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

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

Note 2—Significant Accounting Policies and Related Matters

Significant Accounting Policies

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

Use of Estimates

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

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


8
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

Revenue Recognition

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

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

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

Accounts Receivable

At September 30, 2019 and December 31, 2018, accounts receivable was comprised of the following:
(in thousands)
September 30, 2019
 
December 31, 2018
Oil and gas sales
$
54,233

 
$
40,465

Joint interest
5,172

 
14,058

Other
2,657

 
6,663

Total accounts receivable
$
62,062

 
$
61,186



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

Oil and Natural Gas Properties

A summary of the Company’s oil and natural gas properties, net is as follows:
(in thousands)
September 30, 2019
 
December 31, 2018
Proved oil and natural gas properties
$
2,244,576

 
$
1,746,766

Unproved oil and natural gas properties
133,189

 
158,732

Total oil and natural gas properties
2,377,765

 
1,905,498

Less: Accumulated depletion
(569,733
)
 
(386,883
)
Total oil and natural gas properties, net
$
1,808,032

 
$
1,518,615



Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement costs, are depleted based on proved developed reserves on a field basis. For the three months ended September 30, 2019 and 2018, the Company recorded depletion for oil and natural gas properties of $65.6 million and $57.2 million, respectively. For the nine months ended September 30, 2019 and 2018, the Company recorded depletion for oil and natural gas properties of $184.9 million and $159.0 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated statements of operations.

Leases

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


9
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

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

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

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

Accrued Liabilities

The components of accrued liabilities are shown below:
(in thousands)
September 30, 2019
 
December 31, 2018
Accrued capital expenditures
$
80,153

 
$
74,688

Accrued production and ad valorem taxes
12,765

 
7,802

Accrued interest
12,645

 
4,896

Royalties payable
9,684

 
19,964

Accrued LOE
9,944

 
8,014

Accrued accounts payable
1,454

 
5,941

Other current liabilities
10,210

 
8,707

Total accrued liabilities
$
136,855

 
$
130,012



Recent Accounting Pronouncements

Recently Adopted Accounting Standards

Leases. In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases (Topic 842), which requires entities to determine at the inception of a contract if the contract is, or contains, a lease. ASU 2016-02 retains a distinction between operating and finance leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. Entities are required to recognize operating or finance leases as ROU assets and lease liabilities on the balance sheet as well as disclose key information about leasing arrangements in the notes to the financial statements. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. This ASU does not apply to leases of mineral rights to explore for or use oil and natural gas.

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

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

•the package of transition practical expedients, permitting the Company to not reassess its prior conclusions about lease identification, lease classification and initial direct costs;
•the practical expedient pertaining to land easements, which allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way; and
•the practical expedient to not separate lease and non-lease components.

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

10
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

(in thousands)
Opening Balances as of
January 1, 2019
 
Adoption of ASC 842
 
As Adjusted at
January 1, 2019
Operating lease right-of-use assets (1)
$
—

 
$
73,413

 
$
73,413

 
 
 
 
 
 
Current operating lease liabilities (1)
$
—

 
$
35,043

 
$
35,043

Long-term operating lease liabilities (1)
—

 
42,814

 
42,814

Other long-term liabilities (2)
4,444

 
(4,444
)
 
—

(1)
Represents the recognition of operating lease ROU assets and the associated lease liabilities.
(2)
Represents the derecognition of deferred rent and leasehold incentives that were accounted for under ASC 840.

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

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

Accounting Standards Not Yet Adopted

Financial Instruments: Credit Losses. In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which replaces the current incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2020, with early adoption permitted, and will be applied using a modified retrospective approach which may result in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the Company does not believe the adoption of ASU 2016-13 will have a material impact on its consolidated financial statements.

Note 3—Derivative Instruments

Objectives and Strategies

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

Commodity Derivatives

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

Swaps. The Company receives a fixed price for a specified notional quantity of oil or natural gas, and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices.

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

The following table summarizes the Company’s derivative contracts as of September 30, 2019:
Contract Period
 
Volumes
(MBbls)
 
Wtd Avg Price
($/Bbl)
Oil Swaps: (1)
 

 

Fourth quarter 2019
 
1,932

 
$
59.95

Year ending December 31, 2020
 
7,320

 
$
58.25

Oil Basis Swaps: (2)
 
 
 
 
Fourth quarter 2019
 
2,300

 
$
(4.79
)
Year ending December 31, 2020
 
9,516

 
$
(1.31
)
(1)
The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price.
(2)
The oil basis swap differential price is between Cushing–WTI and Midland–WTI.

11
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)


Counterparty Risk

By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. Where the Company is exposed to credit risk in its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement and monitors the appropriateness of these counterparties on an ongoing basis. Generally, the Company does not require collateral and does not anticipate nonperformance by its counterparties.

At September 30, 2019, the Company had commodity derivative contracts with seven counterparties, all of which were lenders, or affiliates of lenders, under the Company’s Amended and Restated Credit Facility (as defined in Note 4, Debt) and all of which had investment grade credit ratings. These counterparties accounted for all the Company’s counterparty credit exposure related to commodity derivative assets.

Should the creditworthiness of the Company’s counterparties decline, under certain circumstances the Company may have a contractual right of offset against other amounts owed by the Company to the counterparty, but otherwise its ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third-party. In the event of a counterparty default, the Company may sustain a loss and its cash receipts could be negatively impacted.

Financial Statement Presentation

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

The Company estimates the fair value using risk adjusted discounted cash flow calculations. Cash flows are based on published future commodity price curves for the underlying commodity as of the date of the estimate. Due to the volatility of commodity prices, the estimated fair values of the Company’s derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. For more information, refer to Note 9, Fair Value Measurements.

Consolidated Statements of Operations

The Company recognized the following gains (losses) on derivative instruments in its consolidated statements of operations for the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
 
2019
 
2018
Net gain (loss) on settled derivative instruments
$
(3,484
)
 
$
(6,347
)
 
$
(14,651
)
 
$
(33,705
)
Net gain (loss) from the change in fair value of open derivative instruments
42,905

 
(90,169
)
 
(71,051
)
 
(76,721
)
Gain (loss) on derivative instruments, net
$
39,421

 
$
(96,516
)
 
$
(85,702
)
 
$
(110,426
)


Consolidated Balance Sheets

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


12
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of September 30, 2019 and December 31, 2018 (in thousands):
As of September 30, 2019:
 
Balance Sheet Location
 
Gross amounts presented on the balance sheet
 
Netting adjustments not offset on the balance sheet
 
Net amounts
Assets
 
 
 
 
 
 
 
 
Commodity contracts
 
Current assets - derivative instruments
 
$
48,006

 
$
(25,639
)
 
$
22,367

Commodity contracts
 
Noncurrent assets - derivative instruments
 
13,961

 
(4,659
)
 
9,302

Total assets
 
 
 
$
61,967

 
$
(30,298
)
 
$
31,669

Liabilities
 
 
 
 
 
 
 
 
Commodity contracts
 
Current liabilities - derivative instruments
 
$
27,738

 
$
(25,639
)
 
$
2,099

Commodity contracts
 
Noncurrent liabilities - derivative instruments
 
4,659

 
(4,659
)
 
—

Total liabilities
 
 
 
$
32,397

 
$
(30,298
)
 
$
2,099

As of December 31, 2018:
 
Balance Sheet Location
 
Gross amounts presented on the balance sheet
 
Netting adjustments not offset on the balance sheet
 
Net amounts
Assets
 
 
 
 
 
 
 
 
Commodity contracts
 
Current assets - derivative instruments
 
$
103,092

 
$
(18,815
)
 
$
84,277

Commodity contracts
 
Noncurrent assets - derivative instruments
 
31,899

 
(9,668
)
 
22,231

Total assets
 
 
 
$
134,991

 
$
(28,483
)
 
$
106,508

Liabilities
 
 
 
 
 
 
 
 
Commodity contracts
 
Current liabilities - derivative instruments
 
$
23,208

 
$
(18,815
)
 
$
4,393

Commodity contracts
 
Noncurrent liabilities - derivative instruments
 
11,162

 
(9,668
)
 
1,494

Total liabilities
 
 
 
$
34,370

 
$
(28,483
)
 
$
5,887



Note 4—Debt

The Company’s debt consisted of the following at September 30, 2019 and December 31, 2018:
(in thousands)
September 30, 2019
 
December 31, 2018
Senior secured revolving credit facility
$
215,000

 
$
—

5.875% senior unsecured notes due 2026
500,000

 
500,000

Debt issuance costs on senior unsecured notes
(9,731
)
 
(10,761
)
Total long-term debt
$
705,269

 
$
489,239



Senior Secured Revolving Credit Facility

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

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

The Amended and Restated Credit Facility also contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Facility, include requirements to comply with the following financial ratios:
Financial Covenant
 
Required Ratio
Ratio of current assets to liabilities, as defined in the credit agreement
 
Not less than
1.0

to
1.0
Ratio of debt to EBITDAX, as defined in the credit agreement
 
Not greater than
4.0

to
1.0



13
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

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

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

5.875% Senior Unsecured Notes due 2026

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

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

In March 2019 the Company completed an offer to exchange the Senior Notes for registered, publicly tradable notes that have terms identical in all material respects to the Senior Notes (except that the exchange notes do not contain any transfer restrictions).

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

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

Note 5—Equity-based Compensation

Equity-based compensation expense, for each type of equity-based award, was as follows for the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
 
2019
 
2018
Incentive unit awards
$
856

 
$
609

 
$
2,050

 
$
75,767

Restricted stock unit awards
1,624

 
883

 
4,520

 
2,996

Performance stock unit awards
1,403

 
1,016

 
3,987

 
1,513

Restricted stock unit awards issued to nonemployee directors
215

 
106

 
468

 
395

Equity-based compensation expense
$
4,098

 
$
2,614

 
$
11,025

 
$
80,671



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

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


14
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

The following table summarizes the Company’s award activity for incentive units, restricted stock units (“RSU”) and PSUs for the nine months ended September 30, 2019:
 
Incentive Units (2)
 
RSUs
 
PSUs
Unvested at December 31, 2018
5,397,555

 
871,119

 
691,363

Awards Granted (1)
28,991

 
1,232,503

 
657,664

Vested
(2,598,796
)
 
(291,704
)
 
—

Forfeited
(28,991
)
 
(137,510
)
 
(135,299
)
Unvested at September 30, 2019
2,798,759

 
1,674,408

 
1,213,728

(1)
The weighted average grant-date fair value was $8.27 for incentive units, $10.18 for RSUs and $12.63 for PSUs. The weighted average grant-date fair value for PSUs was calculated using a Monte Carlo simulation.
(2)
Included in the unvested incentive units at September 30, 2019 are 2,433,821 units for which equity-based compensation expense has been accelerated and fully recognized.

The following table reflects the future equity-based compensation expense to be recorded for each type of award that was outstanding at September 30, 2019:
 
Incentive Units
 
RSUs (1)
 
PSUs
Compensation costs remaining at September 30, 2019 (in millions)
$
3.5

 
$
13.8

 
$
9.5

Weighted average remaining period at September 30, 2019 (in years)
1.6

 
2.1

 
1.8


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

Note 6—Earnings Per Share

Basic earnings per share is computed by dividing net earnings by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested RSUs and PSUs if including such potential shares of common stock units is dilutive. The PSUs included in the calculation of diluted weighted average shares outstanding are based on the number of shares of common stock that would be issuable if the end of the reporting period was the end of the performance period required for the vesting of such PSU awards. Shares to be issued in exchange for incentive units are already outstanding and will not have a dilutive effect upon vesting. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all awards is antidilutive.

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands, except per share amounts)
2019
 
2018
 
2019
 
2018
Net income (loss) attributable to common stock
$
30,558

 
$
(26,566
)
 
$
(22,423
)
 
$
(20,888
)
 
 
 
 
 
 
 
 
Basic weighted average shares outstanding
213,403

 
213,180

 
213,349

 
213,109

Dilutive unvested RSUs
35

 
—

 
—

 
—

Dilutive unvested PSUs
262

 
—

 
—

 
—

Diluted weighted average shares outstanding
213,700

 
213,180

 
213,349

 
213,109

 
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
Basic
$
0.14

 
$
(0.12
)
 
$
(0.11
)
 
$
(0.10
)
Diluted
$
0.14

 
$
(0.12
)
 
$
(0.11
)
 
$
(0.10
)



15
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

The following table presents the weighted average number of outstanding equity awards that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive. These shares could dilute basic earnings per share in future periods.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
 
2019
 
2018
Number of antidilutive units: (1)
 
 
 
 
 
 
 
Antidilutive unvested RSUs
1,575

 
791

 
1,455

 
721

Antidilutive unvested PSUs
225

 
603

 
1,076

 
496

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

Note 7—Income Taxes

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

Income tax expense was as follows for the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
 
2019
 
2018
Income tax expense (benefit)
$
8,597

 
$
(7,315
)
 
$
(5,986
)
 
$
14,737

Effective tax rate
22.0
%
 
21.6
%
 
21.1
%
 
(239.6
)%

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

Note 8—Asset Retirement Obligations

The following table summarizes the changes in the carrying amount of the asset retirement obligations for the nine months ended September 30, 2019. The current portion of the asset retirement obligation liability is included in accrued liabilities on the consolidated balance sheets.
(in thousands)
 
Asset retirement obligations at January 1, 2019
$
2,072

Liabilities incurred and assumed
902

Liability settlements
(318
)
Revisions of estimated liabilities
717

Accretion
159

Asset retirement obligations at September 30, 2019
3,532

Less current portion of asset retirement obligations
(923
)
Long-term asset retirement obligations
$
2,609



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

Note 9—Fair Value Measurements

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


16
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

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

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

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

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

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Reclassifications of fair value among Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers among Level 1, Level 2 or Level 3 during the nine months ended September 30, 2019.

Assets and liabilities measured on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis. The following table sets forth the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
 
Level 2
(in thousands)
September 30, 2019
 
December 31, 2018
Assets from commodity derivative contracts
$
61,967

 
$
134,991

Liabilities due to commodity derivative contracts
$
32,397

 
$
34,370



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

Fair Value of Other Financial Instruments

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:
 
September 30, 2019
 
December 31, 2018
(in thousands)
Principal Amount
 
Fair Value
 
Principal Amount
 
Fair Value
Long-term debt:
 
 
 
 
 
 
 
Senior secured revolving credit facility
$
215,000

 
$
215,000

 
$
—

 
$
—

5.875% senior unsecured notes due 2026
$
500,000

 
$
501,490

 
$
500,000

 
$
466,250



The fair value of the Amended and Restated Credit Facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and these inputs are classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes at September 30, 2019 was based on the quoted market price and is classified as Level 1 in the fair value hierarchy.

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

17
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)


Assets and liabilities measured on a nonrecurring basis

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

Proved oil and natural gas properties. The Company reviews its proved oil and natural gas properties for impairment whenever facts and circumstances indicate their carrying value may not be recoverable. In such circumstances, the income approach is used to determine the fair value of proved oil and natural gas reserves. Under this approach, the Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs.

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

The following table sets forth the noncash impairments of both proved and unproved properties for the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
 
2019
 
2018
Proved oil and natural gas property impairments
$
—

 
$
—

 
$
—

 
$
—

Unproved oil and natural gas property impairments (1)
31,817

 
—

 
32,763

 
53

 
$
31,817

 
$
—

 
$
32,763

 
$
53

(1)
Impairment of unproved oil and natural gas properties in 2019 primarily resulted from the Company’s ongoing evaluation of its undeveloped Big Tex acreage and the current plan to not drill on certain of these leases before they expire. Impairment of unproved oil and natural gas properties in 2018 resulted from expirations of certain undeveloped leases.

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

Note 10—Leases

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

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

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


18
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

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

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

Lease Costs

Lease cost for operating leases is recognized on a straight-line basis over the lease term. Short-term lease costs exclude expenses related to leases with a lease term of one month or less. Lease costs are presented gross and a portion of these costs will be reimbursed by the Company’s other working interest partners for their proportionate share. The total gross lease cost for the periods indicated are as follows:
 
Three months ended
 
Nine months ended
(in thousands)
September 30, 2019
 
September 30, 2019
Operating lease cost (1)
$
9,297

 
$
27,891

Short-term lease cost (2)
5,273

 
33,553

Variable lease cost (3)
369

 
941

Total lease cost
$
14,939

 
$
62,385

(1)
The total operating lease cost may not agree to the cash paid for operating lease liabilities on the consolidated statements of cash flows due to the timing of cash payments and incurred costs.
(2)
Short-term lease cost during the three months ended September 30, 2019 is primarily related to one short-term drilling rig and certain field equipment. During the three months ended March 31, 2019, costs from the Company’s frac fleets were also included in this amount, which is seen in the nine months ended September 30, 2019. Subsequent to March 31, 2019, the Company determined that the frac fleets are considered to have a term of one month or less and are no longer included in the short-term lease cost disclosure.
(3)
Variable lease costs were not included in the measurement of the Company’s lease balances and primarily relate to common area maintenance charges on the Company’s corporate headquarters.

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

Lease Maturities

The table below reconciles the undiscounted lease payment maturities to the lease liabilities for the Company’s operating leases as of September 30, 2019:
 
Remainder
 
Payments Due by Period for the Year Ending December 31,
 
 
(in thousands)
of 2019
 
2020
 
2021
 
2022
 
2023
 
Thereafter
 
Total
Operating lease payments (1)
$
9,450

 
$
33,428

 
$
1,547

 
$
1,558

 
$
1,589

 
$
7,378

 
$
54,950

Less: amount of lease payments representing interest
 
 
 
 
 
 
 
(3,168
)
Present value of future minimum lease payments
 
 
 
 
 
 
 
51,782

Less: current operating lease liabilities
 
 
 
 
 
 
 
(36,263
)
Long-term operating lease liabilities
 
 
 
 
 
 
 
$
15,519

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


19
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

Supplemental Lease Information

Supplemental information related to the Company’s operating leases was as follows:
 
September 30, 2019
Weighted average remaining lease term - operating leases (in years)
2.8

Weighted average discount rate - operating leases (1)
4.2
%
(1)
Upon adoption of the new lease standard, discount rates used for existing leases were established at January 1, 2019.

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

As described in Note 2, Significant Accounting Policies and Related Matters, the Company adopted ASU 2016-02 using the modified retrospective approach as permitted under ASU 2018-11. This ASU also requires entities electing this transition method to provide the required disclosures under ASC 840 for all periods that continue to be presented in accordance with ASC 840. As such, the Company included the future minimum payments for noncancelable operating leases as of December 31, 2018, in accordance with ASC 840, as follows:
(in thousands)
2019
 
2020
 
2021
 
2022
 
2023
 
Thereafter
 
Total
Operating leases
$
1,547

 
$
1,539

 
$
1,553

 
$
1,559

 
$
1,589

 
$
7,378

 
$
15,165


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

Note 11—Commitments and Contingencies

Commitments

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

Contingencies

Legal Matters

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

Environmental Matters

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

Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both September 30, 2019 and December 31, 2018, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Note 12—Related Party Transactions

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


20
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

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

The following table summarizes fees paid to Oryx and Phoenix for the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
 
2019
 
2018
Oryx via 3rd party shipper (1)
$
—

 
$
6,435

 
$
14,041

 
$
16,719

Oryx (2)
$
32

 
$
140

 
$
548

 
$
440

Phoenix (3)
$
17

 
$
98

 
$
68

 
$
319

(1)
Fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil transportation and gathering agreement are netted against revenue as they are included in the net price paid by the third-party shipper.
(2)
Fees paid to Oryx for the purchase and installation of metering equipment are capitalized to proved properties on the consolidated balance sheets. The Company also received $45 thousand from Oryx during the nine months ended September 30, 2019 related to pipeline easements and right of way agreements.
(3)
Fees paid to Phoenix are capitalized to proved properties on the consolidated balance sheets.

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

Note 13—Subsequent Events

Proposed Merger of Jagged Peak with Parsley Energy, Inc.

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

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

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

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

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

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

21
JAGGED PEAK ENERGY INC.
Notes to Consolidated Financial Statements
(Unaudited)

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

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

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

Waiver to Redetermination Scheduled On or Around October 1, 2019

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

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

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

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

Overview

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

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

•
Brought online 48 gross (40.5 net) wells;
•
Increased average daily production from the first nine months of 2018 by 16% to 38,081 Boe/d, comprised of 76% oil;
•
Grew oil production 14% to 29,073 barrels per day, natural gas production by 13% to 25.0 MMcf/d and NGL production by 32% to 4,836 barrels per day compared to the first nine months of 2018;
•
Impacted by negative natural gas revenues as a result of low and/or negative natural gas prices and the effect of gathering and processing costs; and
•
Recorded impairment expense of $32.8 million largely related to our Big Tex area and our current plan to not drill on certain of these leases before they expire.

Proposed Merger with Parsley Energy

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

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

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

22


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

Impact of Commodity Prices

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

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

For the three and nine months ended September 30, 2019 and 2018, our production revenues were derived from the following:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Oil sales
98
%
 
91
%
 
98
%
 
93
%
Natural gas sales
1
%
 
2
%
 
—
%
 
2
%
Natural gas liquids sales
1
%
 
7
%
 
2
%
 
5
%
Total (1)
100
%
 
100
%
 
100
%
 
100
%
(1)
Our oil, natural gas and NGL revenues do not include the effects of derivatives.

The daily spot prices from published sources for Midland–WTI and for natural gas prices at the Waha Hub fluctuated compared to the corresponding NYMEX prices, as seen in the table below for the periods presented:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Crude Oil (per Bbl):
 
 
 
 
 
 
 
Low NYMEX–WTI price
$
51.14

 
$
65.07

 
$
46.31

 
$
59.20

High NYMEX–WTI price
$
63.10

 
$
74.19

 
$
66.24

 
$
77.41

Low Midland–WTI price
$
50.69

 
$
48.01

 
$
41.09

 
$
48.01

High Midland–WTI price
$
63.20

 
$
66.37

 
$
63.20

 
$
66.91

Natural Gas (per Mcf):
 
 
 
 
 
 
 
Low NYMEX–Henry Hub price
$
2.02

 
$
2.73

 
$
2.02

 
$
2.49

High NYMEX–Henry Hub price
$
2.75

 
$
3.12

 
$
4.25

 
$
6.24

Low Waha Hub price
$
(0.16
)
 
$
0.81

 
$
(4.63
)
 
$
0.81

High Waha Hub price
$
1.93

 
$
2.51

 
$
3.27

 
$
7.27


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

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

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


23

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

The following table presents our average realized commodity prices, the effects of derivative settlements on our realized prices, the average daily NYMEX spot prices from published sources for oil and natural gas index prices, the average Midland–WTI oil spot price and the average Waha Hub natural gas spot price, for the periods presented:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Crude Oil (per Bbl):
 
 
 
 
 
 
 
Average realized price
$
53.55

 
$
55.95

 
$
52.52

 
$
59.15

Average realized price, including derivative settlements
$
52.29

 
$
53.45

 
$
50.67

 
$
54.30

Average NYMEX–WTI price
$
56.34

 
$
69.69

 
$
57.04

 
$
66.93

Average Midland–WTI price
$
56.07

 
$
55.25

 
$
55.85

 
$
59.21

Natural Gas (per Mcf):
 
 
 
 
 
 
 
Average realized price
$
0.31

 
$
1.19

 
$
0.13

 
$
1.29

Average NYMEX–Henry Hub price
$
2.38

 
$
2.93

 
$
2.62

 
$
2.95

Average Waha Hub price
$
0.94

 
$
1.89

 
$
0.78

 
$
2.10

NGLs (per Bbl):
 
 
 
 
 
 
 
Average realized price
$
3.47

 
$
24.81

 
$
6.58

 
$
23.71


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

Derivative Activity

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

As of September 30, 2019, we entered into the following derivative contracts:
Contract Period
 
Volumes
(MBbls)
 
Wtd Avg Price
($/Bbl)
Oil Swaps (entered into as of September 30, 2019): ¹
 
 
 
 
October 1, 2019 through December 31, 2020
 
9,252

 
$
58.60

Oil Basis Swaps (entered into as of September 30, 2019): ²
 
 
 
 
October 1, 2019 through December 31, 2020
 
11,816

 
$
(1.98
)
(1)
The index prices for the oil swaps are based on the NYMEX–WTI (Cushing, OK) monthly average futures price.
(2)
The oil basis swap differential price is between Cushing–WTI and Midland–WTI.

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


24

Results of Operations

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

Revenues

Oil and Natural Gas Revenues.    The following table provides the components of our revenues for the three months ended September 30, 2019 and 2018, as well as each period’s respective average realized prices and production volumes:
 
Three Months Ended September 30,
 
 
 
 
(in thousands or as indicated)
2019
 
2018
 
Change
 
% Change
Production revenues:
 
 
 
 
 
 
 
Oil sales
$
147,710

 
$
141,598

 
$
6,112

 
4
 %
Natural gas sales
727

 
2,552

 
(1,825
)
 
(72
)%
NGL sales
1,628

 
10,814

 
(9,186
)
 
(85
)%
Total production revenues
$
150,065

 
$
154,964

 
$
(4,899
)
 
(3
)%
Average realized price: (1)
 
 
 
 
 
 
 
Oil (per Bbl)
$
53.55

 
$
55.95

 
$
(2.40
)
 
(4
)%
Natural gas (per Mcf)
$
0.31

 
$
1.19

 
$
(0.88
)
 
(74
)%
NGLs (per Bbl)
$
3.47

 
$
24.81

 
$
(21.34
)
 
(86
)%
Total (per Boe)
$
41.51

 
$
46.64

 
$
(5.13
)
 
(11
)%
Production volumes:
 
 
 

 
 
 
 
Oil (MBbls)
2,758

 
2,531

 
227

 
9
 %
Natural gas (MMcf)
2,331

 
2,139

 
192

 
9
 %
NGLs (MBbls)
469

 
436

 
33

 
8
 %
Total (MBoe)
3,616

 
3,323

 
293

 
9
 %
Average daily production volume:
 
 
 

 
 
 
 
Oil (Bbls/d)
29,980

 
27,507

 
2,473

 
9
 %
Natural gas (Mcf/d)
25,339

 
23,245

 
2,094

 
9
 %
NGLs (Bbls/d)
5,096

 
4,738

 
358

 
8
 %
Total (Boe/d)
39,299

 
36,118

 
3,181

 
9
 %
(1)
Average prices shown in the table do not include settlements of commodity derivative transactions.

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

The following table reconciles the change in oil, natural gas and NGL sales by reflecting the effect of changes in volumes and in the underlying commodity prices, from the three months ended September 30, 2018 to the three months ended September 30, 2019:
(in thousands)
Oil sales (1)
 
Natural gas sales (1)
 
NGL sales (1)
 
Total (1)
Three months ended September 30, 2018
$
141,598

 
$
2,552

 
$
10,814

 
$
154,964

Changes due to:
 
 
 
 
 
 
 
Increase (decrease) in production volumes
12,732

 
226

 
819

 
13,777

Increase (decrease) in average realized prices (2)
(6,620
)
 
(2,051
)
 
(10,005
)
 
(18,676
)
Three months ended September 30, 2019
$
147,710

 
$
727

 
$
1,628

 
$
150,065

(1)
The net dollar effect of the increases in production is calculated as the change in period-to-period volumes for oil, natural gas and NGLs multiplied by the prior period average prices. The net dollar effect of the changes in prices is calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and NGLs.
(2)
Natural gas and NGL revenues include gathering and processing costs. For the three months ended September 30, 2019 and 2018, these costs reduced our natural gas revenues by $0.9 million and $1.1 million, respectively, and reduced our NGL prices by $3.8 million and $3.6 million, respectively.

25


Operating Expenses

The following table summarizes our operating expenses for the periods indicated:
 
Three Months Ended September 30,
 
 
 
 
 
Per Boe
(in thousands, except per Boe)
2019
 
2018
 
Change
 
% Change
 
2019
 
2018
Lease operating expenses
$
17,554

 
$
11,184

 
$
6,370

 
57
 %
 
$
4.85

 
$
3.37

Production and ad valorem taxes
11,263

 
9,517

 
1,746

 
18
 %
 
$
3.11

 
$
2.86

Exploration
3

 
23

 
(20
)
 
(87
)%
 
$
—

 
$
0.01

Depletion, depreciation, amortization and accretion
66,069

 
57,660

 
8,409

 
15
 %
 
$
18.27

 
$
17.35

Impairment of unproved oil and natural gas properties
31,817

 
—

 
31,817

 
NM

 
NM

 
NM

Other operating expenses
—

 
19

 
(19
)
 
(100
)%
 
$
—

 
$
0.01

General and administrative (before equity-based compensation)
9,571

 
9,707

 
(136
)
 
(1
)%
 
$
2.65

 
$
2.92

Total operating expenses (before equity-based compensation)
136,277

 
88,110

 
48,167

 
55
 %
 
$
37.69

 
$
26.52

Equity-based compensation
4,098

 
2,614

 
1,484

 
 
 
 
 
 
Total operating expenses
$
140,375

 
$
90,724

 
$
49,651

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

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

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

Depletion, Depreciation, Amortization and Accretion.    The components of depletion, depreciation, amortization and accretion (“DD&A”) expense for the three months ended September 30, 2019 and 2018 are summarized as follows:
 
Three Months Ended September 30,
 
Per Boe
(in thousands)
2019
 
2018
 
2019
 
2018
Depletion of oil and natural gas properties
$
65,569

 
$
57,170

 
$
18.13

 
$
17.20

Depreciation of other property and equipment
437

 
459

 
$
0.12

 
$
0.14

Accretion of asset retirement obligations
63

 
31

 
$
0.02

 
$
0.01

Depletion, depreciation, amortization and accretion
$
66,069

 
$
57,660

 
$
18.27

 
$
17.35


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

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

26


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

Equity-based compensation expense for the three months ended September 30, 2019 and 2018 is summarized as follows:
 
Three Months Ended September 30,
 
 
(in thousands)
2019
 
2018
 
Change
Incentive unit awards
$
856

 
$
609

 
$
247

Restricted stock unit awards
1,839

 
989

 
850

Performance stock unit awards
1,403

 
1,016

 
387

Equity-based compensation expense
$
4,098

 
$
2,614

 
$
1,484


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

Other Income and Expense

The following table summarizes our other income and expenses for the periods indicated:
 
Three Months Ended September 30,
 
 
(in thousands)
2019
 
2018
 
Change
Gain (loss) on commodity derivatives
$
39,421

 
$
(96,516
)
 
$
135,937

Interest expense, net
(9,974
)
 
(8,256
)
 
(1,718
)
Gain on sale of oil and natural gas properties
—

 
6,225

 
(6,225
)
Other, net
18

 
12

 
6

Total other income (expense)
$
29,465

 
$
(98,535
)
 
$
128,000


Gain (loss) on Commodity Derivatives.    We utilize commodity derivative instruments to reduce our exposure to fluctuations in commodity prices. This amount includes (i) the gain (loss) related to derivative contracts that have settled within the period and (ii) the gain (loss) related to fair value adjustments on our open derivative contracts. The following table sets forth these components for the three months ended September 30, 2019 and 2018:
 
Three Months Ended September 30,
(in thousands)
2019
 
2018
Net gain (loss) on settled derivative instruments
$
(3,484
)
 
$
(6,347
)
Net gain (loss) from the change in fair value of open derivative instruments
42,905

 
(90,169
)
Gain (loss) on commodity derivatives
$
39,421

 
$
(96,516
)

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

Interest Expense, net.    The following table summarizes our interest expense for the three months ended September 30, 2019 and 2018:
 
Three Months Ended September 30,
(in thousands)
2019
 
2018
Amended and Restated Credit Facility (1)
$
2,249

 
$
491

Senior Notes
7,343

 
7,322

Amortization of debt issuance costs (2)
594

 
732

Capitalized interest
(212
)
 
(289
)
Interest expense, net
$
9,974

 
$
8,256

(1)
Includes interest on outstanding balances and commitment fees on undrawn balances.
(2)
Includes amortization of debt issuance costs on the Amended and Restated Credit Facility and Senior Notes.


27

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

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

Income tax expense (benefit)

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

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

Revenues

Oil and Natural Gas Revenues.    The following table provides the components of our revenues for the nine months ended September 30, 2019 and 2018, as well as each period’s respective average realized prices and production volumes:
 
Nine Months Ended September 30,
 
 
 
 
(in thousands or as indicated)
2019
 
2018
 
Change
 
% Change
Production revenues:
 
 
 
 
 
 
 
Oil sales
$
416,824

 
$
410,935

 
$
5,889

 
1
 %
Natural gas sales
904

 
7,765

 
(6,861
)
 
(88
)%
NGL sales
8,680

 
23,721

 
(15,041
)
 
(63
)%
Total production revenues
$
426,408

 
$
442,421

 
$
(16,013
)
 
(4
)%
Average realized price: (1)
 
 
 
 
 
 
 
Oil (per Bbl)
$
52.52

 
$
59.15

 
$
(6.63
)
 
(11
)%
Natural gas (per Mcf)
$
0.13

 
$
1.29

 
$
(1.16
)
 
(90
)%
NGLs (per Bbl)
$
6.58

 
$
23.71

 
$
(17.13
)
 
(72
)%
Total (per Boe)
$
41.02

 
$
49.42

 
$
(8.40
)
 
(17
)%
Production volumes:
 
 
 

 
 
 
 
Oil (MBbls)
7,937

 
6,947

 
990

 
14
 %
Natural gas (MMcf)
6,834

 
6,025

 
809

 
13
 %
NGLs (MBbls)
1,320

 
1,001

 
319

 
32
 %
Total (MBoe)
10,396

 
8,952

 
1,444

 
16
 %
Average daily production volume:
 
 
 

 
 
 
 
Oil (Bbls/d)
29,073

 
25,447

 
3,626

 
14
 %
Natural gas (Mcf/d)
25,034

 
22,069

 
2,965

 
13
 %
NGLs (Bbls/d)
4,836

 
3,665

 
1,171

 
32
 %
Total (Boe/d)
38,081

 
32,790

 
5,291

 
16
 %
(1)
Average prices shown in the table do not include settlements of commodity derivative transactions.

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


28

The following table reconciles the change in oil, natural gas and NGL sales by reflecting the effect of changes in volumes and in the underlying commodity prices, from the nine months ended September 30, 2018 to the nine months ended September 30, 2019:
(in thousands)
Oil sales (1)
 
Natural gas sales (1)
 
NGL sales (1)
 
Total (1)
Nine months ended September 30, 2018
$
410,935

 
$
7,765

 
$
23,721

 
$
442,421

Changes due to:
 
 
 
 
 
 
 
Increase (decrease) in production volumes
58,511

 
1,067

 
7,573

 
67,151

Increase (decrease) in average realized prices (2)
(52,622
)
 
(7,928
)
 
(22,614
)
 
(83,164
)
Nine months ended September 30, 2019
$
416,824

 
$
904

 
$
8,680

 
$
426,408

(1)
The net dollar effect of the increases in production is calculated as the change in period-to-period volumes for oil, natural gas and NGLs multiplied by the prior period average prices. The net dollar effect of the changes in prices is calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and NGLs.
(2)
Natural gas and NGL revenues include gathering and processing costs. For the nine months ended September 30, 2019 and 2018, these costs reduced our natural gas revenues by $3.1 million and $3.0 million, respectively, and reduced our NGL revenues by $11.3 million and $8.2 million, respectively.

Operating Expenses

The following table summarizes our operating expenses for the periods indicated:
 
Nine Months Ended September 30,
 
 
 
 
 
Per Boe
(in thousands, except per Boe)
2019
 
2018
 
Change
 
% Change
 
2019
 
2018
Lease operating expenses
$
46,758

 
$
31,390

 
$
15,368

 
49
 %
 
$
4.50

 
$
3.51

Production and ad valorem taxes
32,100

 
26,437

 
5,663

 
21
 %
 
$
3.09

 
$
2.95

Exploration
3

 
24

 
(21
)
 
(88
)%
 
$
—

 
$
—

Depletion, depreciation, amortization and accretion
186,365

 
160,552

 
25,813

 
16
 %
 
$
17.93

 
$
17.93

Impairment of unproved oil and natural gas properties
32,763

 
53

 
32,710

 
NM

 
NM

 
NM

Other operating expenses
3,206

 
65

 
3,141

 
NM

 
$
0.31

 
$
0.01

General and administrative (before equity-based compensation)
29,116

 
28,800

 
316

 
1
 %
 
$
2.80

 
$
3.22

Total operating expenses (before equity-based compensation)
330,311

 
247,321

 
82,990

 
34
 %
 
$
31.77

 
$
27.63

Equity-based compensation
11,025

 
80,671

 
(69,646
)
 
 
 
 
 
 
Total operating expenses
$
341,336

 
$
327,992

 
$
13,344

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

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

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


29

Depletion, Depreciation, Amortization and Accretion.    The components of DD&A expense for the nine months ended September 30, 2019 and 2018 are summarized as follows:
 
Nine Months Ended September 30,
 
Per Boe
(in thousands)
2019
 
2018
 
2019
 
2018
Depletion of oil and natural gas properties
$
184,928

 
$
158,975

 
$
17.79

 
$
17.76

Depreciation of other property and equipment
1,278

 
1,490

 
$
0.12

 
$
0.16

Accretion of asset retirement obligations
159

 
87

 
$
0.02

 
$
0.01

Depletion, depreciation, amortization and accretion
$
186,365

 
$
160,552

 
$
17.93

 
$
17.93


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

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

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

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

Equity-based compensation expense for the nine months ended September 30, 2019 and 2018 is summarized as follows:
 
Nine Months Ended September 30,
 
 
(in thousands)
2019
 
2018
 
Change
Incentive unit awards
$
2,050

 
$
75,767

 
$
(73,717
)
Restricted stock unit awards
4,988

 
3,391

 
1,597

Performance stock unit awards
3,987

 
1,513

 
2,474

Equity-based compensation expense
$
11,025

 
$
80,671

 
$
(69,646
)

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

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

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


30

Other Income and Expense

The following table summarizes our other income and expenses for the periods indicated:
 
Nine Months Ended September 30,
 
 
(in thousands)
2019
 
2018
 
Change
Gain (loss) on commodity derivatives
$
(85,702
)
 
$
(110,426
)
 
$
24,724

Interest expense, net
(27,683
)
 
(17,095
)
 
(10,588
)
Gain on sale of oil and natural gas properties
—

 
6,225

 
(6,225
)
Other, net
(105
)
 
30

 
(135
)
Total other income (expense)
$
(113,490
)
 
$
(121,266
)
 
$
7,776


Gain (loss) on Commodity Derivatives.    We utilize commodity derivative instruments to reduce our exposure to fluctuations in commodity prices. This amount includes (i) the gain (loss) related to derivative contracts that have settled within the period and (ii) the gain (loss) related to fair value adjustments on our open derivative contracts. The following table sets forth these components for the nine months ended September 30, 2019 and 2018:
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
Net gain (loss) on settled derivative instruments
$
(14,651
)
 
$
(33,705
)
Net gain (loss) from the change in fair value of open derivative instruments
(71,051
)
 
(76,721
)
Gain (loss) on commodity derivatives
$
(85,702
)
 
$
(110,426
)

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

Interest Expense, net.    The following table summarizes our interest expense for the nine months ended September 30, 2019 and 2018:
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
Amended and Restated Credit Facility (1)
$
4,566

 
$
4,528

Senior Notes
22,031

 
11,668

Amortization of debt issuance costs (2)
1,770

 
1,753

Capitalized interest
(684
)
 
(854
)
Interest expense, net
$
27,683

 
$
17,095

(1)
Includes interest on outstanding balances and commitment fees on undrawn balances.
(2)
Includes amortization of debt issuance costs on the Amended and Restated Credit Facility and Senior Notes.

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

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

Income tax expense (benefit)

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


31

Capital Commitments, Capital Resources and Liquidity

Capital Commitments

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

2019 Capital Budget

Our 2019 capital budget for development of oil and gas properties and infrastructure is as follows:
(in millions)
 
 
 
Drilling and completion
$
580.0

—
$
630.0

Water infrastructure
25.0

—
35.0

Total
$
605.0

—
$
665.0


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

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

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

Capital Expenditures

Capital expenditures for oil and gas acquisitions, exploration, development and infrastructure activities are summarized below:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
 
2019
 
2018
Acquisitions
 
 
 
 
 
 
 
Proved properties
$
375

 
$
—

 
$
7,782

 
$
—

Unproved properties (1)
17,316

 
7,575

 
25,295

 
18,670

Development costs
162,571

 
151,797

 
451,261

 
535,590

Infrastructure costs
4,520

 
5,439

 
25,678

 
13,440

Exploration costs
3

 
23

 
3

 
24

Total oil and gas capital expenditures
$
184,785

 
$
164,834

 
$
510,019

 
$
567,724

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


32

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

The following table reflects wells that began producing in the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Gross wells
 
 
 
 
 
 
 
Operated
17

 
10

 
40

 
36

Non-operated
8

 
1

 
8

 
13

 
25

 
11

 
48

 
49

Net wells
 
 
 
 
 
 
 
Operated
16.2

 
9.8

 
38.4

 
33.5

Non-operated
2.1

 
0.1

 
2.1

 
5.1

 
18.3

 
9.9

 
40.5

 
38.6


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

Contractual Obligations

A summary of our contractual obligations as of September 30, 2019 is provided in the following table:
 
Remainder
 
Payments Due by Period for the Year Ending December 31,
 
 
(in thousands)
of 2019
 
2020
 
2021
 
2022
 
2023
 
Thereafter
 
Total
Senior secured credit facility (1)
$
—

 
$
—

 
$
—

 
$
—

 
$
215,000

 
$
—

 
$
215,000

Senior notes—principal
—

 
—

 
—

 
—

 
—

 
500,000

 
500,000

Senior notes—interest (2)
14,688

 
29,375

 
29,375

 
29,375

 
29,375

 
73,437

 
205,625

Operating leases (3)
9,450

 
33,428

 
1,547

 
1,558

 
1,589

 
7,378

 
54,950

Service and purchase contracts (4)
10,305

 
15,514

 
3,706

 
3,633

 
3,633

 
13,926

 
50,717

Total
$
34,443

 
$
78,317

 
$
34,628

 
$
34,566

 
$
249,597

 
$
594,741

 
$
1,026,292

(1)
This table does not include future commitment fees, interest expense or other costs related to our Amended and Restated Credit Facility because we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. As of September 30, 2019, we had $215.0 million outstanding under our Amended and Restated Credit Facility. The borrowing base and elected commitments remained at $900.0 million and $540.0 million, respectively, and the Company had $325.0 million of elected commitments available.
(2)
Interest represents the scheduled cash payments on the Senior Notes.
(3)
Relates to lease payment maturities for our operating leases, which include drilling rigs, our corporate headquarters and certain office equipment. See Note 10, Leases, in “Part I. Financial Information - Item 1. Financial Statements” for more information on our operating leases.
(4)
Primarily relates to a casing and tubing purchase agreement, a coiled tubing service agreement and a retail power purchase agreement.

Additionally, in 2018 the Company entered into a 5-year oil marketing agreement that became effective on October 1, 2019 and links a portion of the Company’s oil production to Gulf Coast pricing. This agreement specifies a minimum gross volume commitment of 30,000 barrels of oil per day. If the Company is not able to provide the contractual quantity to the buyer, it would be subject to a deficiency payment relative to a price difference on the deficient volume. Based on its current and projected production levels, the Company does not believe a deficiency payment will be required under this agreement.

Off-Balance Sheet Arrangements

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

Capital Resources and Liquidity

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

33

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

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

Cash Flows

The following table summarizes our cash flows for the periods indicated:
 
Nine Months Ended September 30,
(in thousands)
2019
 
2018
Net cash provided by operating activities
$
272,701

 
$
317,747

Net cash used in investing activities
$
(511,449
)
 
$
(564,781
)
Net cash provided by financing activities
$
214,122

 
$
331,450


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

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

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

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

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

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

Senior Secured Revolving Credit Facility

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

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


34

The Amended and Restated Credit Facility contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Facility, include requirements to comply with the following financial ratios:
Financial Covenant
 
Required Ratio
Ratio of current assets to liabilities, as defined in the credit agreement
 
Not less than
1.0
to
1.0
Ratio of debt to EBITDAX, as defined in the credit agreement
 
Not greater than
4.0
to
1.0

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

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

Critical Accounting Policies and Estimates

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

Recent Accounting Pronouncements

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

Item 3.
Quantitative and Qualitative Disclosures About Market Risk

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

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

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

Commodity Price Risk

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


35

The following table shows how hypothetical changes in the realized prices we receive for our commodity sales would have impacted revenue for the nine months ended September 30, 2019:
 
 
 
Sensitivity Analysis
(in thousands)
Revenue (1)
 
% of Total
 
Change in Realized Prices
 
Impact on Revenue
Oil
$
416,824

 
98%
 
+ / - 10% per barrel
 
+ / -
$
41,682

Natural gas
904

 
—%
 
+ / - 10% per Mcf
 
+ / -
$
90

NGL
8,680

 
2%
 
+ / - 10% per barrel
 
+ / -
$
868

Total
$
426,408

 
100%
 
 
 
 
 
(1)
Our oil, natural gas and NGL revenues do not include the effects of derivatives instruments.

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

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

The following table reconciles the changes that occurred in the fair values of our derivative instruments from December 31, 2018 to September 30, 2019:
 
Commodity Derivative Instruments
(in thousands)
Net Assets (Liabilities)
Fair value of open contracts at December 31, 2018
$
100,621

Gain (loss) on commodity derivatives
(85,702
)
Net cash payments on settled derivatives
14,651

Fair value of open contracts at September 30, 2019
$
29,570


The following table sets forth the hypothetical impact on the fair value of our net oil derivative asset of $29.6 million as of September 30, 2019, using an average increase or decrease of 10% to the commodity prices:
 
 
Change in Forward Commodity Prices
(in thousands)
 
10% Increase
 
10% Decrease
Increase (decrease) to net oil derivative asset as of September 30, 2019
 
$
48,253

 
$
(48,253
)

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

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

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

Interest Rate Risk

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

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


36

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

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

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

Item 4.
Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

37



PART II—OTHER INFORMATION

Item 1.
Legal Proceedings

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

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

Item 1A.
Risk Factors

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

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

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

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

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

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

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

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

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

38

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

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

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

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

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

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

•
we may experience negative reactions from the financial markets, including negative impacts on the market price of our common stock;
•
the manner in which customers, vendors, business partners and other third parties perceive the Company may be negatively impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the marketplace more broadly;
•
we will still be required to pay certain significant costs relating to the Merger, such as legal, accounting, financial advisor and printing fees;
•
we may experience negative reactions from employees; and
•
we will have expended time and resources that could otherwise have been spent on our existing businesses and the pursuit of other opportunities that could have been beneficial to the Company, and our ongoing business and financial results may be adversely affected.

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

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

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

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


39

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

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

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

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

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

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

Recent sales of unregistered securities

None.

Purchases of equity securities by the issuer and affiliated purchasers

The following table summarizes the repurchase of our common stock during the three months ended September 30, 2019:
Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
July 1, 2019 - July 31, 2019
 
1,786

 
$
8.75

 
—

 
—

August 1, 2019 - August 31, 2019
 
—

 
$
—

 
—

 
—

September 1, 2019 - September 30, 2019
 
1,418

 
$
7.48

 
—

 
—

Total
 
3,204

 
$
8.12

 
—

 
—

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

Item 3.
Defaults Upon Senior Securities

None.

Item 4.
Mine Safety Disclosures

Not applicable.

Item 5.
Other Information

None.


40

Item 6.
Exhibits

Exhibit Number
 
Description of Exhibit
±2.1
 
10.1
 
10.2
 
*10.3
 
*31.1
 
*31.2
 
**32.1
 
**32.2
 
*101.INS
 
Inline XBRL Instance Document - The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document.
*101.SCH
 
Inline XBRL Schema Document
*101.CAL
 
Inline XBRL Calculation Linkbase Document
*101.LAB
 
Inline XBRL Label Linkbase Document
*101.PRE
 
Inline XBRL Presentation Linkbase Document
*101.DEF
 
Inline XBRL Taxonomy Extension Definition Linkbase Document
*104
 
Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
 
 
 
 
 
 
*
 
Filed herewith.
**
 
Furnished herewith.
±
 
Schedules have been omitted pursuant to Item 601(b)(2)(a)(5) of Regulation S-K. The registrant hereby undertakes to furnish supplementally copies of any of the omitted schedules upon request by the SEC.

41



SIGNATURES

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

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


42
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