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