|
|
Item 1.
|
Financial Statements
|
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
|
2017
|
|
2016
|
ASSETS
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
198,809
|
|
|
$
|
11,727
|
|
Accounts receivable
|
16,124
|
|
|
10,327
|
|
Derivative instruments
|
4,858
|
|
|
—
|
|
Other current assets
|
1,298
|
|
|
3,412
|
|
Total current assets
|
221,089
|
|
|
25,466
|
|
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
653,300
|
|
|
531,121
|
|
Accumulated depletion
|
(71,194
|
)
|
|
(57,529
|
)
|
Total oil and gas properties, net
|
582,106
|
|
|
473,592
|
|
Other property and equipment, net
|
3,092
|
|
|
3,001
|
|
Total property and equipment, net
|
585,198
|
|
|
476,593
|
|
OTHER NONCURRENT ASSETS
|
|
|
|
|
|
Unamortized debt issuance costs
|
2,386
|
|
|
1,503
|
|
Derivative instruments
|
5,691
|
|
|
—
|
|
Other assets
|
117
|
|
|
14,830
|
|
Total noncurrent assets
|
8,194
|
|
|
16,333
|
|
TOTAL ASSETS
|
$
|
814,481
|
|
|
$
|
518,392
|
|
LIABILITIES AND STOCKHOLDERS’ / MEMBERS’ EQUITY
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
Accounts payable
|
$
|
7,939
|
|
|
$
|
7,629
|
|
Accrued liabilities
|
59,826
|
|
|
39,225
|
|
Derivative instruments
|
4,601
|
|
|
9,567
|
|
Total current liabilities
|
72,366
|
|
|
56,421
|
|
LONG-TERM LIABILITIES
|
|
|
|
|
|
Senior secured revolving credit facility
|
—
|
|
|
132,000
|
|
Derivative instruments
|
689
|
|
|
3,287
|
|
Asset retirement obligations
|
500
|
|
|
448
|
|
Deferred income taxes
|
89,368
|
|
|
—
|
|
Other long-term liabilities
|
84
|
|
|
124
|
|
Total long-term liabilities
|
90,641
|
|
|
135,859
|
|
Commitments and contingencies
|
|
|
|
|
|
STOCKHOLDERS’ / MEMBERS’ EQUITY
|
|
|
|
|
|
Members' equity
|
—
|
|
|
346,098
|
|
Preferred stock, $0.01 par value, 50,000,000 shares authorized, no shares issued at March 31, 2017; no shares authorized or issued at December 31, 2016
|
—
|
|
|
—
|
|
Common stock, $0.01 par value; 1,000,000,000 shares authorized, 212,937,746 shares issued at March 31, 2017; no shares authorized or issued at December 31, 2016
|
2,129
|
|
|
—
|
|
Additional paid-in capital
|
739,750
|
|
|
—
|
|
Accumulated deficit
|
(90,405
|
)
|
|
(19,986
|
)
|
Total stockholders’ / members’ equity
|
651,474
|
|
|
326,112
|
|
TOTAL LIABILITIES AND STOCKHOLDERS’ / MEMBERS’ EQUITY
|
$
|
814,481
|
|
|
$
|
518,392
|
|
The accompanying Notes are an integral part of these unaudited consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
REVENUES
|
|
|
|
|
Oil sales
|
$
|
36,765
|
|
|
$
|
9,274
|
|
Natural gas sales
|
917
|
|
|
280
|
|
NGL sales
|
1,518
|
|
|
428
|
|
Other operating revenues
|
188
|
|
|
263
|
|
Total revenues
|
39,388
|
|
|
10,245
|
|
OPERATING EXPENSES
|
|
|
|
|
|
Lease operating expenses
|
1,610
|
|
|
1,796
|
|
Gathering and transportation expenses
|
392
|
|
|
150
|
|
Production and ad valorem taxes
|
2,640
|
|
|
701
|
|
Depletion, depreciation, amortization and accretion
|
14,062
|
|
|
8,712
|
|
Impairment of oil and natural gas properties and dry hole costs
|
7
|
|
|
246
|
|
General and administrative expenses (including equity-based compensation of $408,964 and $0 for the three months ended March 31, 2017 and 2016, respectively)
|
413,551
|
|
|
3,332
|
|
Other operating expenses
|
141
|
|
|
1,466
|
|
Total operating expenses
|
432,403
|
|
|
16,403
|
|
INCOME (LOSS) FROM OPERATIONS
|
(393,015
|
)
|
|
(6,158
|
)
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
Gain (loss) on commodity derivatives
|
17,042
|
|
|
(1,059
|
)
|
Interest expense, net
|
(711
|
)
|
|
(233
|
)
|
Other, net
|
171
|
|
|
—
|
|
Total other income (expense)
|
16,502
|
|
|
(1,292
|
)
|
INCOME (LOSS) BEFORE INCOME TAX
|
(376,513
|
)
|
|
(7,450
|
)
|
Income tax expense (benefit)
|
89,368
|
|
|
—
|
|
NET INCOME (LOSS)
|
(465,881
|
)
|
|
(7,450
|
)
|
Less: Net loss attributable to Jagged Peak Energy LLC (predecessor)
|
(375,476
|
)
|
|
(7,450
|
)
|
NET INCOME (LOSS) ATTRIBUTABLE TO JAGGED PEAK ENERGY INC. STOCKHOLDERS
|
$
|
(90,405
|
)
|
|
$
|
—
|
|
|
|
|
|
Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share:
|
|
|
|
Basic
|
$
|
(0.42
|
)
|
|
|
Diluted
|
$
|
(0.42
|
)
|
|
|
|
|
|
|
Weighted-average common shares outstanding:
|
|
|
|
Basic
|
212,938
|
|
|
|
Diluted
|
212,938
|
|
|
|
The accompanying Notes are an integral part of these unaudited consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members' Equity
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Accumulated Deficit
|
|
Total Stockholders' Equity / Members' Equity
|
|
|
Shares
|
|
Amount
|
|
|
|
BALANCE AT DECEMBER 31, 2016
|
$
|
346,098
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(19,986
|
)
|
|
$
|
326,112
|
|
Deemed contribution - incentive unit compensation
|
364,314
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
364,314
|
|
Net income (loss) for the period prior to the corporate reorganization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(375,476
|
)
|
|
(375,476
|
)
|
Balance prior to corporate reorganization and initial public offering
|
710,412
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(395,462
|
)
|
|
314,950
|
|
Issuance of common stock in corporate reorganization
|
(710,412
|
)
|
|
184,605
|
|
|
1,846
|
|
|
313,104
|
|
|
395,462
|
|
|
—
|
|
Issuance of common stock in initial public offering, net of offering costs
|
—
|
|
|
28,333
|
|
|
283
|
|
|
396,708
|
|
|
—
|
|
|
396,991
|
|
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
29,938
|
|
|
—
|
|
|
29,938
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(90,405
|
)
|
|
(90,405
|
)
|
BALANCE AT MARCH 31, 2017
|
$
|
—
|
|
|
212,938
|
|
|
$
|
2,129
|
|
|
$
|
739,750
|
|
|
$
|
(90,405
|
)
|
|
$
|
651,474
|
|
The accompanying Notes are an integral part of these unaudited consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
Net income (loss)
|
$
|
(465,881
|
)
|
|
$
|
(7,450
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities
|
|
|
|
|
|
Depletion, depreciation, amortization and accretion expense
|
14,062
|
|
|
8,712
|
|
Impairment of oil and natural gas properties and dry hole costs
|
7
|
|
|
246
|
|
Amortization of debt issuance costs
|
117
|
|
|
31
|
|
Deferred income taxes
|
89,368
|
|
|
—
|
|
Equity-based compensation
|
408,964
|
|
|
—
|
|
(Gain) loss on commodity derivatives
|
(17,042
|
)
|
|
1,059
|
|
Net cash receipts (payments) on settled derivatives
|
(1,071
|
)
|
|
—
|
|
Other
|
(39
|
)
|
|
(39
|
)
|
Change in operating assets and liabilities:
|
|
|
|
|
|
Accounts receivable and other current assets
|
(6,325
|
)
|
|
2,272
|
|
Other assets
|
—
|
|
|
10
|
|
Accounts payable and accrued liabilities
|
(459
|
)
|
|
223
|
|
Net cash provided by operating activities
|
21,701
|
|
|
5,064
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
Leasehold and acquisition costs
|
(25,628
|
)
|
|
(16,989
|
)
|
Development of oil and natural gas properties
|
(74,293
|
)
|
|
(17,282
|
)
|
Other capital expenditures
|
(763
|
)
|
|
(677
|
)
|
Net cash used in investing activities
|
(100,684
|
)
|
|
(34,948
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
Proceeds from issuance of common stock in initial public offering, net of underwriting fees
|
401,625
|
|
|
—
|
|
Proceeds from common units issued
|
—
|
|
|
16,600
|
|
Proceeds from credit facility
|
10,000
|
|
|
15,000
|
|
Repayment of credit facility
|
(142,000
|
)
|
|
—
|
|
Debt issuance costs
|
(1,000
|
)
|
|
(26
|
)
|
Costs relating to initial public offering
|
(2,560
|
)
|
|
—
|
|
Net cash provided by financing activities
|
266,065
|
|
|
31,574
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS
|
187,082
|
|
|
1,690
|
|
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
|
11,727
|
|
|
14,165
|
|
CASH AND CASH EQUIVALENTS, END OF PERIOD
|
$
|
198,809
|
|
|
$
|
15,855
|
|
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
|
|
|
|
|
|
Interest paid, net of capitalized interest
|
$
|
697
|
|
|
$
|
166
|
|
Cash paid for income taxes
|
—
|
|
|
—
|
|
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
|
|
|
|
|
|
Accrued capital expenditures
|
$
|
58,518
|
|
|
$
|
23,237
|
|
Asset retirement obligations
|
40
|
|
|
147
|
|
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
|
|
|
|
Accrued offering costs
|
$
|
657
|
|
|
$
|
—
|
|
The accompanying Notes are an integral part of these unaudited consolidated and combined financial statements.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
Note 1—Organization, Operations and Basis of Presentation
Organization and Operations
Jagged Peak Energy Inc. (either individually or together with its subsidiaries, as the context requires, “Jagged Peak” or the “Company”) is a growth-oriented, 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, a sub-basin of the Permian Basin of West Texas. The Company’s acreage is located on large, contiguous blocks in the adjacent counties of Winkler, Ward, Reeves and Pecos, with significant oil-in-place within multiple stacked hydrocarbon-bearing formations.
Corporate Reorganization and Initial Public Offering
Jagged Peak is a Delaware corporation formed in September 2016, as a wholly owned subsidiary of Jagged Peak Energy LLC (“JPE LLC”), a Delaware limited liability company formed in April 2013. JPE LLC was formed by an affiliate of Quantum Energy Partners (“Quantum”) and key members of Jagged Peak’s management team. Jagged Peak was formed to become the holding company of JPE LLC in connection with Jagged Peak’s initial public offering (the “IPO”).
Immediately prior to the IPO, all capital interests and management incentive units (“MIUs”) in JPE LLC were converted into a single class of units which were then converted into our common stock. Certain members of management and employees contributed common stock received upon the conversion of unvested or unallocated MIUs to JPE Management Holdings LLC, a limited liability company formed in connection with the IPO for the purpose of holding the unvested or unallocated common stock. Also immediately prior to the IPO, a corporate reorganization (the “corporate reorganization”) took place whereby Jagged Peak, initially formed as a subsidiary of JPE LLC, formed JPE Merger Sub LLC as a subsidiary. JPE LLC merged into JPE Merger Sub LLC, with JPE LLC as the surviving entity. As a result, JPE LLC became a wholly owned subsidiary of Jagged Peak. Prior to the corporate reorganization, Quantum owned
98.6%
of the membership interests of JPE LLC. Following the corporate reorganization and IPO, Quantum owned
68.7%
of the outstanding common stock of Jagged Peak. As all power and authority to control the core functions of Jagged Peak and JPE LLC were, and continue to be, controlled by Quantum, the corporate reorganization was treated as a reorganization of entities under common control and the results of JPE LLC have been consolidated and combined for all periods.
On January 27, 2017, the Company initiated its IPO of common stock to the public, and began trading on the New York Stock Exchange. During the IPO, the Company and selling stockholders sold
31,599,334
shares at
$15.00
per share, raising
$474.0 million
of gross proceeds. Of the
31,599,334
shares issued to the public,
28,333,334
shares were sold by the Company, and
3,266,000
shares were sold by the selling stockholders. The gross proceeds of the IPO to the Company, based on the public offering price of
$15.00
per share, were approximately
$425.0 million
, which resulted in net proceeds to the Company of
$397.0 million
after deducting expenses and underwriting discounts and commissions of approximately
$28.0 million
. The Company did not receive any proceeds from the sale of the shares by the selling stockholders. A portion of the proceeds from the IPO were used to repay the entire outstanding balance on JPE LLC’s credit facility of
$142.0 million
, as of the date the IPO proceeds were received. The remainder of the net proceeds from the IPO are being used to fund a portion of the Company’s 2017 capital expenditures program, and for other general corporate purposes.
Basis of Presentation
The accompanying unaudited consolidated and combined financial statements include the accounts of Jagged Peak and JPE LLC, and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, and should be read in conjunction with the financial statements, summary of significant accounting policies and footnotes included in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2016
, as amended (the “
2016
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 Company’s
2016
Form 10-K. All significant intercompany and intra-company balances and transactions have been eliminated.
It is the opinion of management that all adjustments, consisting of normal recurring adjustments, considered necessary for a fair presentation of interim financial information, have been included. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identical to its comprehensive income or loss. Operating results for the
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
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, natural production declines, the uncertainty of exploration and development drilling results, the fair value of derivative instruments, and other factors.
The unaudited consolidated and combined financial statements for periods prior to January 27, 2017 reflect the historical results of JPE LLC, other than the equity-based compensation expense and deferred tax expense, as further described in Notes 6 and 8, respectively.
Certain reclassifications have been made to prior period amounts 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 to the Company’s consolidated financial statements in its
2016
Form 10-K, and are supplemented by the notes to the consolidated and combined financial statements in this Quarterly Report on Form 10-Q. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in these notes to our consolidated and combined financial statements.
Use of Estimates
In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Estimates made in preparing these consolidated and combined financial statements include, among other things, (1) estimates relating to certain oil and natural gas revenue and costs, (2) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment calculations, (3) estimates of timing and costs used in calculating asset retirement obligations and impairment, (4) estimates used in developing fair value assumptions and estimates, and (5) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in the assumptions could have a significant impact on results in future periods.
Oil and Natural Gas Properties
A summary of the Company’s oil and natural gas properties, net is as follows:
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
|
(in thousands)
|
Proved oil and natural gas properties
|
$
|
480,743
|
|
|
$
|
375,129
|
|
Unproved oil and natural gas properties
|
172,557
|
|
|
155,992
|
|
Total oil and natural gas properties
|
653,300
|
|
|
531,121
|
|
Less: Accumulated depletion
|
(71,194
|
)
|
|
(57,529
|
)
|
Total oil and natural gas properties, net
|
$
|
582,106
|
|
|
$
|
473,592
|
|
Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. For the three months ended
March 31, 2017
and
2016
, the Company recorded depletion for oil and natural gas properties of
$13.7 million
and
$8.6 million
, respectively.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
Equity-based Compensation
The Company recognizes compensation cost related to all equity-based awards in the financial statements based on their estimated grant-date fair value. The Company may grant various types of equity-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions) and restricted stock units. Service-based restricted stock and units are valued using the market price of Jagged Peak’s common stock on the grant date. The fair value of the market condition-based restricted stock units are based on the grant-date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period, and is recognized in general and administrative expense on the consolidated and combined statements of operations. The Company has elected to account for forfeitures in compensation expense as they occur. See Note
6
for additional information regarding equity-based compensation.
Income Taxes
The Company is a subchapter C corporation and is subject to U.S. federal and state income taxes. Income taxes are accounted for under the asset and liability method. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which the Company operates for the year in which those temporary differences are expected to be recovered or settled. The Company classifies all deferred tax assets and liabilities as noncurrent. The Company recognizes the financial statement effects of a tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination. Net deferred tax assets are then reduced by a valuation allowance if the Company believes it is more-likely-than-not such net deferred tax assets will not be realized.
Recent Accounting Pronouncements
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers (Topic 606)
, which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new guidance will require a company to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-11, which rescinds the U.S. Securities and Exchange Commission (“SEC”) accounting guidance regarding the use of the entitlements method for recognition of natural gas revenues. The new standards are effective for the Company on January 1, 2018. Early adoption is permitted for fiscal years beginning after December 31, 2016. The standards can be adopted using either a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09. The Company intends to adopt this standard on January 1, 2018, but has not yet selected a transition method. The Company does not believe the effect of adoption will be material to its financial statements because it follows the sales method of accounting for its oil, natural gas and NGL production, which is generally consistent with the new revenue recognition model. However, the Company anticipates the new standard will result in expanded disclosure requirements, although it cannot yet determine the extent of those disclosure requirements on the Company.
In February 2016, the FASB issued ASU 2016-02,
Leases (Topic 842)
, which requires all leases with a term greater than one year to be recognized on the balance sheet as lease assets and lease liabilities. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. The new standard is effective for the Company on January 1, 2019. Although early adoption is permitted, the Company does not plan to early adopt the standard. The ASU requires the use of the modified retrospective approach, whereby lessees will be required to recognize and measure leases at the beginning of the earliest period presented. The Company is still in the process of evaluating the impact of this new standard; however, the Company believes the initial impact of adopting the standard will result in increases to its assets and liabilities on its consolidated balance sheets, and changes to the presentation of certain operating expenses on its consolidated statements of operations.
In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting (ASU 2017-09). This ASU clarifies which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The standard is effective for the Company on January 1, 2018,
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
with early adoption permitted. The impact of this new standard will depend on the extent and nature of future changes to the terms of Company's share-based payment awards.
Note 3—Derivative Instruments
The Company hedges a portion of its crude oil sales through derivative instruments to mitigate volatility in commodity prices. The use of these instruments exposes the Company to market basis differential risk if the WTI price does not move in parity with the Company’s underlying sales of crude oil produced in the Southern Delaware Basin.
The Company’s derivative instruments are carried at fair value on the consolidated and combined balance sheets. The Company estimates the fair value using risk adjusted discounted cash flow calculations. Cash flows are based on published future commodity price curves for the underlying commodity as of the date of the estimate. Due to the volatility of commodity prices, the estimated fair values of the Company’s derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. For more information, refer to Note
4
,
Fair Value Measurements
.
As of
March 31, 2017
, the Company hedged the commodity prices associated with a portion of its expected future oil volumes by entering into swap and basis swap derivative financial instruments. With swaps, the Company typically receives an agreed upon fixed price for a specified notional quantity of oil or natural gas, and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices. Basis swap contracts establish the differential between Cushing WTI prices and Midland WTI prices. The Company’s commodity derivatives may expose it to the risk of financial loss in certain circumstances. The Company’s derivative arrangements provide protection on the hedged volumes if market prices decline below the prices at which these derivatives are set. If market prices rise above the prices at which the Company has hedged, the Company will receive less income on the hedged volumes than it would receive in the absence of hedges.
The following table summarizes the Company’s derivative contracts as of
March 31, 2017
:
|
|
|
|
|
|
|
|
|
Contract Period
|
|
Volumes
(Bbls)
|
|
Wtd Avg Price
($/Bbl)
|
Oil Swaps
(1)
:
|
|
|
|
|
Second quarter 2017
|
|
588,175
|
|
|
$
|
50.75
|
|
Third quarter 2017
|
|
836,450
|
|
|
$
|
51.85
|
|
Fourth quarter 2017
|
|
873,200
|
|
|
$
|
52.17
|
|
Total 2017
|
|
2,297,825
|
|
|
$
|
51.69
|
|
Year ending December 31, 2018
|
|
2,708,350
|
|
|
$
|
53.36
|
|
Year ending December 31, 2019
|
|
365,000
|
|
|
$
|
55.55
|
|
Oil Basis Swaps
(2)
:
|
|
|
|
|
Year ending December 31, 2018
|
|
365,000
|
|
|
$
|
(1.39
|
)
|
_______________________________________________________________________________
|
|
(1)
|
The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price.
|
|
|
(2)
|
The basis differential price is between Midland–WTI and Cushing–WTI.
|
The Company has elected to not apply hedge accounting, and as a result, its earnings are affected by the use of the mark-to-market method of accounting for derivative financial instruments. The changes in fair value of these instruments are recognized through earnings as other income or expense rather than deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity price indices. The ultimate gain or loss upon settlement of these transactions is recognized in earnings as other income or expense. Cash settlements of the Company’s contracts are included in cash flows from operating activities in the Company’s statements of cash flows.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
Subsequent to
March 31, 2017
, the Company entered into the following derivative contracts:
|
|
|
|
|
|
|
|
|
Contract Period
|
|
Volumes
(Bbls)
|
|
Wtd Avg Price
($/Bbl)
|
Oil Swaps
(1)
:
|
|
|
|
|
Third quarter 2017
|
|
61,000
|
|
|
$
|
54.00
|
|
Fourth quarter 2017
|
|
161,000
|
|
|
$
|
53.70
|
|
Total 2017
|
|
222,000
|
|
|
$
|
53.78
|
|
Year ending December 31, 2018
|
|
365,000
|
|
|
$
|
53.48
|
|
Year ending December 31, 2019
|
|
912,500
|
|
|
$
|
52.70
|
|
_______________________________________________________________________________
|
|
(1)
|
The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price.
|
The Company recognized the following gains (losses) in earnings for the periods indicated:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
|
(in thousands)
|
Gain (loss) on derivatives instruments, net
|
$
|
17,042
|
|
|
$
|
(1,059
|
)
|
Cash settlements of derivatives (received) paid, net
|
$
|
1,071
|
|
|
$
|
—
|
|
The Company’s derivative contracts are carried at their fair value on the Company’s consolidated and combined balance sheets using Level 2 inputs, and are subject to industry standard master netting arrangements, which allow the Company to offset recognized asset and liability fair value amounts on contracts with the same counterparty. The Company’s policy is to not offset these positions in its consolidated and combined balance sheets.
The following tables present the amounts and classifications of the Company’s derivative assets and liabilities as of
March 31, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
Balance Sheet Location
|
|
Asset
|
|
Liability
|
|
|
|
|
(in thousands)
|
Commodity contracts
|
|
Current assets – derivative instruments
|
|
$
|
4,858
|
|
|
$
|
—
|
|
Commodity contracts
|
|
Noncurrent assets – derivative instruments
|
|
5,691
|
|
|
—
|
|
Commodity contracts
|
|
Current liabilities – derivative instruments
|
|
—
|
|
|
4,601
|
|
Commodity contracts
|
|
Noncurrent liabilities – derivative instruments
|
|
—
|
|
|
689
|
|
Total gross amounts presented in accompanying balance sheets
|
|
10,549
|
|
|
5,290
|
|
Less: amounts not offset in the accompanying balance sheets
|
|
(5,290
|
)
|
|
(5,290
|
)
|
Net amounts
|
|
|
|
$
|
5,259
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
Balance Sheet Location
|
|
Asset
|
|
Liability
|
|
|
|
|
(in thousands)
|
Commodity contracts
|
|
Current liabilities – derivative instruments
|
|
$
|
—
|
|
|
$
|
9,567
|
|
Commodity contracts
|
|
Noncurrent liabilities – derivative instruments
|
|
—
|
|
|
3,287
|
|
Total gross amounts presented in accompanying balance sheets
|
|
—
|
|
|
12,854
|
|
Less: amounts not offset in the accompanying balance sheets
|
|
—
|
|
|
—
|
|
Net amounts
|
|
|
|
$
|
—
|
|
|
$
|
12,854
|
|
Derivative Counterparty Risk
Where the Company is exposed to credit risk in its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
of these limits on an ongoing basis. Generally, the Company does not require collateral and does not anticipate nonperformance by its counterparties.
At
March 31, 2017
, the Company had commodity derivative contracts with
three
counterparties, all of which were lenders under the Company’s amended and restated credit facility and all of which had investment grade credit ratings. These counterparties accounted for all the Company’s counterparty credit exposure related to commodity derivative assets.
Note 4—Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Financial assets and liabilities are measured at fair value on a recurring basis. Nonfinancial assets and liabilities, such as the initial measurement of asset retirement obligations and proved oil and natural gas properties upon acquisition or impairment, are recognized at fair value on a nonrecurring basis.
The Company categorizes the inputs to the fair value of its financial assets and liabilities using a three-tier fair value hierarchy, established by the FASB, that prioritizes the significant inputs used in measuring fair value:
Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.
Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry standard models that consider various assumptions, including quoted prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in the category include nonexchange-traded derivatives such as over-the-counter forwards, swaps and options.
Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value, and the company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Assets and liabilities measured on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The Company’s open commodity derivative instruments were in a
net asset
position at
March 31, 2017
. To determine the fair value at the end of each reporting period, the Company computes discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. The Company compares these prices to the price parameters contained in our hedge contracts to determine estimated future cash inflows or outflows, which are then discounted. The fair values of the Company’s commodity derivative assets and liabilities include a measure of credit risk. These valuations are Level 2 inputs.
The following table is a listing of the Company’s assets and liabilities that were measured at fair value on a recurring basis as of
March 31, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
Level 2
|
|
March 31, 2017
|
|
December 31, 2016
|
|
(in thousands)
|
Assets from commodity derivative contracts
|
$
|
10,549
|
|
|
$
|
—
|
|
Liabilities from commodity derivative contracts
|
5,290
|
|
|
12,854
|
|
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
Assets and liabilities measured on a nonrecurring basis
The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its nonfinancial assets and liabilities, such as the acquisition or impairment of proved and unproved oil and gas properties and the inception value of asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations.
The Company reviews its proved oil and natural gas properties for impairment whenever facts and circumstances indicate their carrying value may not be recoverable. In such circumstances, the income approach is used to determine the fair value of proved oil and natural gas reserves. Under this approach, the Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs.
No
impairments were recorded on proved properties during the
three
months ended
March 31, 2017
and
2016
.
Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Company uses a market approach, and takes into account future development plans, remaining lease term, drilling results, and reservoir performance. The Company recorded impairment of unproved oil and gas properties expense of
$7,000
and
$0.2 million
for the three months ended
March 31, 2017
and
2016
, respectively, resulting from lease expirations.
The inception value of the Company’s AROs 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 inflows and outflows. Given the unobservable nature of these inputs, they represent within Level 3 inputs.
The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation approach based on inputs that are non-observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.
Fair Value of Other Financial Instruments
The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, other current assets, accounts payable, and accrued liabilities that approximate fair value due to the nature of the instrument and the short-term maturities of these instruments.
Note 5—Debt Obligations
In June 2015, JPE LLC entered into a
five
-year
$500.0 million
senior secured revolving credit facility (“JPE LLC’s credit facility”). At
December 31, 2016
, JPE LLC’s credit facility, as amended, had a borrowing base of
$160.0 million
, with
$132.0 million
outstanding under the credit facility, and
$28.0 million
in unused borrowing capacity.
In January 2017, JPE LLC’s credit facility borrowing base was increased to
$180.0 million
, and the number of lenders was increased from
five
banks to
nine
banks.
In February 2017, the Company, as parent guarantor, and JPE LLC, as borrower, entered into an amended and restated credit facility with Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (the “amended and restated credit facility”). The borrowing base under the amended and restated credit facility remained at
$180.0 million
, and borrowings bear interest, at the Company’s option, at either (i) the greatest of (a) the prime rate as determined by the
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
administrative agent, (b) the federal funds effective rate plus
0.50%
, and (c) the thirty-day adjusted LIBOR plus
1.0%
, in each case, plus a margin that varies from
1.25%
to
2.25%
per annum according to the total facility utilization, (ii) the adjusted LIBOR rate plus a margin that varies from
2.25%
to
3.25%
per annum according to the total facility utilization or (iii) the applicable LIBOR market index rate plus a margin that varies from
2.25%
to
3.25%
per annum according to the Company’s total facility utilization. The Company pays a commitment fee of
0.50%
per annum on the unutilized portion of the amended and restated credit facility. Further, the amended and restated credit facility no longer contains the minimum hedging requirements that existed in JPE LLC’s credit facility.
The amended and restated credit facility matures on February 1, 2022, and is subject to semiannual borrowing base redeterminations on or around April 1 and October 1 of each year. The most recent redetermination was completed in April 2017, which resulted in an increase to the borrowing base from
$180.0 million
to
$250.0 million
.
The amended and restated credit facility is secured by oil and natural gas properties representing at least
80%
of the value of the Company’s proved reserves. The amended and restated credit facility contains certain covenants, including among others, restrictions on indebtedness, restrictions on liens, restrictions on investments, restrictions on mergers, restrictions on sales of assets, restrictions on dividends and payments to the Company’s capital interest holders, and restrictions on the Company’s hedging activity.
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 agreement, include requirements to comply with the following financial ratios:
|
|
•
|
a current ratio, which is the ratio of consolidated current assets (including unused commitments under the credit facility and excluding noncash assets related to asset retirement obligations and derivatives) to consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and noncash liabilities related to asset retirement obligations and derivatives), as of the last day of each fiscal quarter, of not less than
1.0
to
1.0
; and
|
|
|
•
|
a leverage ratio, which is the ratio of consolidated Debt (as defined in our credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in the credit agreement) to EBITDAX (as defined in the credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than
4.0
to
1.0
.
|
As of
March 31, 2017
, the Company was in compliance with its financial covenants.
Following the IPO, the outstanding balance under JPE LLC’s credit facility was paid in full, and there was
no
outstanding balance under the amended and restated credit facility as of
March 31, 2017
.
Note 6—Equity-based Compensation
In connection with the IPO, the Company adopted the Jagged Peak Energy Inc. 2017 Long Term Incentive Plan (the “Plan”), which allows the Company to grant up to
21,200,000
equity-based compensation awards to employees and directors of the Company. The Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, performance awards, and other types of awards. The terms and conditions of the awards granted are established by the Company’s Board of Directors. As of
March 31, 2017
,
no
awards had been granted under the Plan.
Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated and combined statements of operations, was as follows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
|
(in thousands)
|
Profits interests awards
|
$
|
408,964
|
|
|
$
|
—
|
|
Total equity-based compensation expense
|
$
|
408,964
|
|
|
$
|
—
|
|
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
Profits Interests Awards
In connection with its formation in April 2013, JPE LLC established an incentive pool plan, whereby JPE LLC granted MIUs to employees and selected other participants. The MIUs were considered “profits interests” that participated in certain events whereupon distributions would be made to MIU holders (only after certain return thresholds were achieved by the capital interests) following a qualifying initial public offering, sale, merger, or other qualifying transaction involving the stock or assets of JPE LLC (“Vesting Event”).
The MIUs were accounted for under FASB ASC Topic 710,
Compensation–General
, which requires compensation expense for the MIUs to be recognized when all performance, market and service conditions are probable of being satisfied, which is generally upon a Vesting Event. As of and through December 31, 2016, the vesting of the MIUs was not deemed probable, therefore
no
expense was recognized through December 31, 2016.
The corporate reorganization provided a mechanism by which all capital interests and MIUs in JPE LLC were converted into a single class of units, which were then converted into the Company’s common stock. A portion of these shares vested and a portion were transferred to JPE Management Holdings LLC (“Management Holdco”) and became subject to the terms and conditions of the amended and restated JPE Management Holdings LLC limited liability company agreement (the “Management Holdco LLC Agreement”). As a result of the IPO, the satisfaction of all conditions relating to MIUs in JPE LLC held by the current and former officers and employees who owned equity interests in JPE LLC, was deemed probable. As a result, based on the Company’s IPO price of
$15.00
per share, compensation expense of
$379.0 million
was recognized for the vested shares of common stock at the IPO date, all of which was noncash except for
$14.7 million
related to a management incentive advance payment made in April 2016.
The shares of common stock transferred to Management Holdco are accounted for under ASC 718,
Compensation–Stock Compensation
, and generally vest over
three
years. The grant-date fair value of these awards was
$15.00
, and the remaining compensation expense will be recognized ratably according to the terms of the Management Holdco LLC Agreement. Accordingly, the Company recognized
$7.7 million
of equity-based compensation expense related to the shares held by Management Holdco. The Company also recognized an additional
$22.2 million
of equity-based compensation related to awards held by Management Holdco which were modified in conjunction with a March 2017 separation agreement of a former executive officer. The Company will recognize the remaining noncash compensation expense related to awards held at Management Holdco of approximately
$108.3 million
over the approximate
three
years of remaining vesting term. Any unallocated shares of Company common stock held at Management Holdco will be valued using the stock price on the date of grant, and the Company will recognize expense over the related service period. The equity-based compensation relative to these shares of common stock transferred to Management Holdco is not deductible for Federal or state income tax purposes in 2017 or in the future.
Note 7—Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net earnings by the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock units, if any, if including such potential shares of common stock units is dilutive. Through
March 31, 2017
, the Company did not issue any shares under its long-term incentive plan; as such, there are no potentially dilutive shares as of that date.
For the
three
months ended
March 31, 2017
, the Company’s EPS calculation includes only the net loss for the period subsequent to the corporate reorganization and IPO, and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017, to
March 31, 2017
.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
|
|
|
|
|
|
From January 27, 2017, to
|
|
March 31, 2017
|
|
(in thousands)
|
Net income (loss) attributable to Jagged Peak Energy Inc. stockholders
|
$
|
(90,405
|
)
|
|
|
Weighted average shares outstanding - basic
|
212,938
|
|
Effect of diluted securities:
|
—
|
|
Weighted average shares outstanding - diluted
|
212,938
|
|
|
|
Net income (loss) per common share:
|
|
Basic
|
$
|
(0.42
|
)
|
Diluted
|
$
|
(0.42
|
)
|
Note 8—Income Taxes
JPE LLC was organized as a limited liability company and treated as a pass-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of the Company from January 27, 2017 through March 31, 2017 in the accompanying consolidated and combined financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the change in tax status as a result of the corporate reorganization, the Company established a
$79.1 million
provision for deferred income taxes, which was recognized as tax expense from continuing operations.
The components of the Company’s provision for income taxes are as follows:
|
|
|
|
|
|
Three Months Ended
|
|
March 31, 2017
|
|
(in thousands)
|
Current income tax expense:
|
|
Federal
|
$
|
—
|
|
State
|
—
|
|
|
—
|
|
Deferred income tax expense:
|
|
Federal
|
87,479
|
|
State
|
1,889
|
|
|
89,368
|
|
Provision for income taxes
|
$
|
89,368
|
|
Included in the deferred federal income tax provision above is the
$79.1 million
related to the Company’s change in tax status.
A reconciliation of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense is as follows:
|
|
|
|
|
|
Three Months Ended
|
|
March 31, 2017
|
|
(in thousands)
|
Income (loss) before income taxes
|
$
|
(376,513
|
)
|
Less: net loss prior to corporate reorganization
|
(375,476
|
)
|
Income (loss) before income taxes subsequent to corporate reorganization
|
$
|
(1,037
|
)
|
|
|
Income taxes at the federal statutory rate
|
$
|
(363
|
)
|
Income tax expense relating to change in tax status
|
78,019
|
|
State income taxes, net of federal benefit
|
1,228
|
|
Nondeductible equity-based compensation
|
10,478
|
|
Other permanent differences
|
6
|
|
Income tax expense (benefit)
|
$
|
89,368
|
|
Effective tax rate
|
(23.7
|
)%
|
Prior to the Company’s change in tax status in January 2017, income taxes did not significantly impact the results of operations.
The components of the Company’s deferred tax assets and liabilities as of
March 31, 2017
are as follows:
|
|
|
|
|
|
March 31, 2017
|
|
(in thousands)
|
Deferred tax assets:
|
|
Net operating loss carryforwards
|
$
|
2,796
|
|
Other
|
555
|
|
Total deferred tax assets
|
3,351
|
|
Deferred tax liabilities:
|
|
Oil and natural gas properties
|
90,853
|
|
Commodity derivatives
|
1,866
|
|
Total deferred tax liabilities
|
92,719
|
|
Net deferred tax liabilities
|
$
|
(89,368
|
)
|
The Company had U.S. net operating losses of approximately
$7.9 million
, which expire in 2036. Deferred tax assets are reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized. At
March 31, 2017
, the Company did
not
have a valuation allowance.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. At
March 31, 2017
, the Company had
no
unrecognized tax benefits that would impact the effective tax rate and has made
no
provisions for interest or penalties related to uncertain tax positions.
The Company files income tax returns in the U.S. federal jurisdiction, Texas and Colorado. There are currently no federal or state income tax examinations underway. The Company’s U.S. federal income tax returns remain open to examination by the taxing authorities for tax years 2014 through 2016, and its Texas and Colorado tax returns remain open to examination for the years 2013 through 2016.
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
(Unaudited)
Note 9—Asset Retirement Obligations
The following table summarizes the changes in asset retirement obligations in the carrying amount of the asset retirement obligation for the
three
months ended
March 31, 2017
:
|
|
|
|
|
(in thousands)
|
|
Asset retirement obligations at January 1, 2017
|
$
|
448
|
|
Liabilities incurred and assumed
|
45
|
|
Liability settlements and disposals
|
—
|
|
Revisions of estimated liabilities
|
(5
|
)
|
Accretion
|
12
|
|
Asset retirement obligations at March 31, 2017
|
500
|
|
Less current portion of asset retirement obligations
|
—
|
|
Long-term asset retirement obligations
|
$
|
500
|
|
Note 10—Commitments and Contingencies
Commitments
There were no material changes in commitments during the first three months of 2017, except as discussed below. Please refer to Note 9,
Commitments and Contingencies
, in the 2016 Form 10-K for additional discussion.
During the
first
quarter of
2017
, the Company entered into
one
new drilling rig contract, to bring the total rigs under contract to
six
at
March 31, 2017
. If the Company were to terminate these contracts at
March 31, 2017
, it would be required to pay early termination penalties of
$8.2 million
. In the first quarter of 2016, the Company terminated
one
drilling rig and incurred early termination charges of approximately
$0.2 million
. These charges are reflected as other operating costs in the consolidated and combined statements of operations.
The Company has commitments for office space and equipment under operating lease arrangements totaling
$1.3 million
.
Contingencies
Legal Matters
In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
Environmental Matters
The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both
March 31, 2017
and
December 31, 2016
, the Company had
no
environmental matters requiring specific disclosure or requiring the recognition of a liability.
Note 11—Related Party Transactions
Quantum employs certain members of the Company’s board of directors and had significant capital interests in JPE LLC. After giving effect to the IPO, Quantum owns
68.7%
of the Company’s common stock.
Quantum owns a
41.5%
interest in Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”). The Company has a
12
-year crude oil gathering agreement with Oryx whereby Oryx provides midstream gathering services to the Company. Under that agreement, the Company has the right to designate, and has designated, a third-party shipper to market the Company’s crude oil. During the three months ended
March 31, 2017
, the Company’s third-party shipper paid Oryx
$1.4 million
in transportation fees pursuant to this agreement. In addition, during the first quarter ended
March 31, 2017
, the Company paid fees to Oryx of
$0.3 million
for the purchase and maintenance of connecting equipment. For the same period of 2016, the Company paid fees to Oryx of
$0.8 million
for the purchase and maintenance of connecting equipment.
Quantum also owns a
61%
interest in Phoenix Lease Services, LLC (“Phoenix”), and an indirect interest in Trident Water Services, LLC (“Trident”), a wholly owned subsidiary of Phoenix. The Company regularly leases frac tanks and other oil field equipment from Phoenix, and also regularly uses water transfer services provided by Trident. The Company is under no obligation to use either provider, and both provide services only when selected as a vendor through the normal bidding process. During the three months ended
March 31, 2017
, the Company paid fees of
$0.1 million
and
$0.2 million
related to such services provided by Phoenix and Trident, respectively. During the same period of 2016, the Company paid fees of
$0.1 million
and
$0.3 million
related to such services provided by Phoenix and Trident, respectively.
At
March 31, 2017
and
December 31, 2016
, the Company had outstanding payables to the aforementioned related parties of
$0.8 million
and
$0.7 million
, respectively.
|
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
The following discussion and analysis should be read in conjunction with our consolidated and combined financial statements and related notes presented in this Quarterly Report on Form 10-Q as well as our audited consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended
December 31, 2016
. The following discussion and analysis contains forward-looking statements, including, without limitation, statements related to our future plans, estimates, beliefs and expected performance. Please see “Cautionary Statement Concerning Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q and “Part 1, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended
December 31, 2016
.
In this section, references to “Jagged Peak,” “the Company,” “we,” “us” and “our” refer to Jagged Peak Energy Inc. and its subsidiaries, after the initial public offering of Jagged Peak (the “IPO”) and, prior to the IPO, to Jagged Peak Energy LLC (“JPE LLC”).
Jagged Peak Energy Inc. and our Predecessor
Jagged Peak was formed in September 2016 and, prior to the consummation of our IPO, did not have historical financial operating results. For purposes of this Quarterly Report, our accounting predecessor reflects the results of JPE LLC, which was formed in 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Southern Delaware Basin of the Permian Basin. In connection with the IPO, a corporate reorganization took place whereby JPE LLC became a wholly owned subsidiary of Jagged Peak.
Overview
We are a growth-oriented, 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, a sub-basin of the Permian Basin and one of the most prolific unconventional resource plays in North America. Our acreage is located on large, contiguous blocks in the adjacent Texas counties of Winkler, Ward, Reeves and Pecos, with significant original oil-in-place within multiple stacked hydrocarbon-bearing formations.
We have assembled a portfolio of contiguous acreage in the core oil window of the Southern Delaware Basin. This acreage is characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that provide attractive growth and return opportunities. At
March 31, 2017
, our acreage position was approximately
68,546
net acres. We divide our current areas of operation into three distinct areas: (1) Cochise, with
13,319
net acres, (2) Whiskey River, with
33,218
net acres, and (3) Big Tex, with
22,009
net acres.
We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operating improvements and cost efficiencies. As the operator of approximately
97%
of our acreage, we have the flexibility to manage our development program, which allows us to optimize our field-level returns and profitability.
Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. Compared to the first
three
months of
2016
, our realized oil price for the first
three
months of
2017
increased
65%
to
$49.33
per barrel, our realized natural gas price
improved
39%
to
$2.48
per Mcf, and our realized price for NGLs
improved
by
73%
to
$20.61
per barrel between the same periods. See “Sources of Our Revenues” below for further information regarding our realized commodity prices.
Factors Affecting the Comparability of Our Results of Operations
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, primarily for the reasons described below.
Equity-based Compensation
In conjunction with the closing of the IPO, we recognized equity-based compensation expense of: (1)
$379.0 million
related to MIUs in JPE LLC; and (2)
$7.7 million
related to shares of common stock transferred to Management Holdco that will vest over the terms of the Management Holdco LLC Agreement. Please refer to Note 6,
Equity-based Compensation
, for additional information on equity-based compensation.
Public Company Expenses
As a result of our IPO, we will incur direct, incremental general and administrative (“G&A”) expenses as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, corporate tax return preparation, increased independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental G&A expenses are not included in the predecessor’s historical results of operations.
Income Taxes
As a result of our corporate reorganization, we became subject to federal and state income tax. The change in tax status required the recognition of deferred tax assets and liabilities for the temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately
$79.1 million
was recognized as tax expense from continuing operations. For periods following completion of the corporate reorganization, we began recording income taxes associated with our status as a corporation. From the date of the corporate reorganization through
March 31, 2017
, we recognized
$10.3 million
of income tax expense. Please refer to Note 8,
Income Taxes
, for more information on income taxes.
Increased Drilling Activity
Since commencing our drilling program in late 2013, we operated an average of one horizontal drilling rig through June 2016.We began operating our second and third rigs in July of 2016. At
March 31, 2017
, we were operating
six
horizontal rigs. During the remainder of 2017, we expect to operate a
five
to
six
-rig drilling program, but may have more or less than these depending on operating requirements and conditions. We also expect to operate
two
to
four
fracturing fleets, as needed, to complete wells in a timely manner. During the three months ended
March 31, 2017
, we completed
7
gross (
6.9
net) wells. Our average daily production has grown from
4,102
Boe/d during the first
three
months of
2016
to
9,785
Boe/d for the same period of
2017
. In the three months ended
March 31, 2017
, we spent
$99.7 million
for drilling and completing wells and on infrastructure costs. This compares to
$29.4 million
that we spent in the three months ended
March 31, 2016
, and $158.3 million that we spent in all of 2016 for drilling and completion.
Summary of Operating and Financial Results Comparing the
Three Months Ended March 31, 2017
and
2016
|
|
•
|
Successfully drilled and completed
7
gross (
6.9
net) wells, all within the Southern Delaware Basin;
|
|
|
•
|
Increased average daily production by
139%
to
9,785
Boe/d, comprised of
85%
oil;
|
|
|
•
|
Daily oil production grew
142%
to
8,281
barrels per day, natural gas volumes increased by
137%
to
4.1
MMcf/d and NGL volumes rose
108%
to
819
barrels per day;
|
|
|
•
|
Production revenues increased
293%
to
$39.2 million
;
|
|
|
•
|
Expanded our borrowing base under our amended and restated credit facility from
$160.0 million
, at December 31, 2016, to
$180.0 million
, at
March 31, 2017
;
|
|
|
•
|
Cash flow from operating activities of
$21.7 million
was
329%
higher than the same period of the previous year;
|
|
|
•
|
Recorded a
$17.0 million
gain on commodity derivative instruments; and
|
|
|
•
|
Incurred equity-based compensation expense of
$409.0 million
, all of which was noncash except for $14.7 million related to an advance made in April 2016.
|
In addition, in April 2017, we completed our most recent borrowing base redetermination, which resulted in an increase to the borrowing base from
$180.0 million
to
$250.0 million
.
Sources of Our Revenues
Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. For the
three
months ended
March 31, 2017
, our production revenues were derived
94%
from oil sales,
2%
from natural gas sales and
4%
from NGL sales. Our oil, natural gas and NGL revenues do not include the effects of derivatives.
Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. A $1.00 per barrel change in our realized oil price would have resulted in a
$0.7 million
change in oil revenues. A $0.10 per Mcf change in our realized natural gas price would have resulted in a
$37 thousand
change in our natural gas revenues. A $1.00 per barrel change in NGL prices would have changed NGL revenue by
$0.1 million
.
The following table presents our average realized commodity prices, the effects of derivative settlements on our realized prices, and certain major U.S index prices.
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
Crude Oil (per Bbl):
|
|
|
|
|
|
Average NYMEX price
|
$
|
51.62
|
|
|
$
|
33.35
|
|
Realized price, before the effects of derivative settlements
|
$
|
49.33
|
|
|
$
|
29.81
|
|
Realized price, after the effects of derivative settlements
|
$
|
47.89
|
|
|
$
|
29.81
|
|
Natural Gas (per Mcf):
|
|
|
|
|
|
Average NYMEX price
|
$
|
3.02
|
|
|
$
|
1.99
|
|
Realized price
|
$
|
2.48
|
|
|
$
|
1.78
|
|
NGLs (per Bbl):
|
|
|
|
|
|
Average realized NGL price
|
$
|
20.61
|
|
|
$
|
11.92
|
|
While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials for these products.
See “Results of Operations” below for an analysis of the impact changes in realized prices had on our revenues.
In addition to sales of oil, natural gas, and NGLs, we derive a minimal portion of our revenues from third party sales of fresh water and produced water disposal services. These revenues are reflected as other operating revenues in the consolidated and combined statements of operations.
Production Results
The following table presents production volumes for the
three
months ended
March 31, 2017
and
2016
:
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
Oil (MBbls)
|
745
|
|
|
311
|
|
Natural gas (MMcf)
|
370
|
|
|
158
|
|
NGLs (MBbls)
|
74
|
|
|
36
|
|
Total (MBoe)
|
881
|
|
|
373
|
|
Average net daily production (Boe/d)
|
9,785
|
|
|
4,102
|
|
Production Volumes Directly Impact Our Results of Operations
As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through drilling, as well as acquisitions. Our ability to add reserves through drilling projects and acquisitions is dependent on many factors, including our ability to increase our levels of cash flow from operations, borrow or raise capital, obtain regulatory approvals, procure materials, services and personnel and successfully identify and consummate acquisitions.
Derivative Activity
Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. As of
March 31, 2017
, we had entered into derivative oil swap contracts covering periods from
April 1, 2017
through
December 31, 2019
for approximately
5.4
MMbls of our projected oil production at a weighted average WTI oil price of
$52.79
per barrel. We also have a basis differential contract between Midland, TX and Cushing, OK covering
0.4
MMbls in 2018 at a weighted average price of
$(1.39)
per barrel. These hedging instruments allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. This will provide increased certainty of cash flows for funding our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. In the future, we may seek to hedge price risk associated with our natural gas and NGL production. See “Item 3—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.
Results of Operations
Comparison of the three months ended
March 31, 2017
versus
March 31, 2016
Oil and Natural Gas Revenues.
The following table provides the components of our production revenues for the three months ended
March 31, 2017
and
2016
, as well as each period’s respective average prices and production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
(in thousands or as indicated)
|
2017
|
|
2016
|
|
Change
|
|
% Change
|
Production Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
$
|
36,765
|
|
|
$
|
9,274
|
|
|
$
|
27,491
|
|
|
296
|
%
|
Natural gas sales
|
917
|
|
|
280
|
|
|
637
|
|
|
228
|
%
|
NGL sales
|
1,518
|
|
|
428
|
|
|
1,090
|
|
|
255
|
%
|
Total production revenues
|
$
|
39,200
|
|
|
$
|
9,982
|
|
|
$
|
29,218
|
|
|
293
|
%
|
Average sales price
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
49.33
|
|
|
$
|
29.81
|
|
|
$
|
19.52
|
|
|
65
|
%
|
Natural gas (per Mcf)
|
$
|
2.48
|
|
|
$
|
1.78
|
|
|
$
|
0.70
|
|
|
39
|
%
|
NGLs (per Bbl)
|
$
|
20.61
|
|
|
$
|
11.92
|
|
|
$
|
8.69
|
|
|
73
|
%
|
Total (per Boe)
|
$
|
44.52
|
|
|
$
|
26.74
|
|
|
$
|
17.78
|
|
|
66
|
%
|
Production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
745
|
|
|
311
|
|
|
434
|
|
|
140
|
%
|
Natural gas (MMcf)
|
370
|
|
|
158
|
|
|
212
|
|
|
134
|
%
|
NGLs (MBbls)
|
74
|
|
|
36
|
|
|
38
|
|
|
106
|
%
|
Total (MBoe)
|
881
|
|
|
373
|
|
|
508
|
|
|
136
|
%
|
Average daily production volume:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/d)
|
8,281
|
|
|
3,418
|
|
|
4,863
|
|
|
142
|
%
|
Natural gas (Mcf/d)
|
4,109
|
|
|
1,734
|
|
|
2,375
|
|
|
137
|
%
|
NGLs (Bbls/d)
|
819
|
|
|
394
|
|
|
425
|
|
|
108
|
%
|
Total (Boe/d)
|
9,785
|
|
|
4,102
|
|
|
5,683
|
|
|
139
|
%
|
_______________________________________________________________________________
|
|
(1)
|
Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.
|
As reflected in the table above, our total production revenue for the first
three
months of
2017
was
293%
, or
$29.2 million
, higher than that of the same period from
2016
. The increase is primarily due to higher sales volumes, along with higher realized commodity prices during the first
three
months of
2017
. Our aggregate production volumes in the first
three
months of
2017
were
881
MBoe, comprised of
85%
oil,
7%
natural gas and
8%
NGLs. This represents an increase of
136%
over the first
three
months of
2016
aggregate production volumes of
373
MBoe, consisting of
83%
oil,
7%
natural gas and
10%
NGLs.
Increased production volumes accounted for an approximate
$13.8 million
increase in quarter-over-quarter production revenues, while increases in our total average sales prices accounted for an approximate
$15.4 million
increase in production revenues for the same period. Production increases are largely related to our active drilling program over the last 12 months.
During the
three
months ended
March 31, 2017
, oil revenues increased
296%
, or
$27.5 million
, due to a
140%
increase in production volumes and a
65%
increase in the average realized price when compared to the same period from the prior year. Natural gas revenues increased
228%
to
$0.9 million
during the
three
months ended
March 31, 2017
from
$0.3 million
during the
three
months ended
March 31, 2016
. The increase is attributable to a
134%
increase in volumes and a
39%
increase in the average sales price. During the first
three
months of
2017
, NGL revenues increased
255%
, or
$1.1 million
, due to a
106%
increase in sales volumes and a
73%
increase in the average realized price.
Other operating revenues relate to sales of fresh water and water disposal services to third parties. During the first
three
months of
2017
and
2016
, we recognized other operating revenue of
$0.2 million
and
$0.3 million
, respectively.
Operating Expenses.
We present per-Boe information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis.
The following table summarizes our expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
Per Boe
|
(in thousands)
|
2017
|
|
2016
|
|
Change
|
|
% Change
|
|
2017
|
|
2016
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
$
|
1,610
|
|
|
$
|
1,796
|
|
|
$
|
(186
|
)
|
|
(10
|
)%
|
|
$
|
1.83
|
|
|
$
|
4.81
|
|
Gathering and transportation expenses
|
392
|
|
|
150
|
|
|
242
|
|
|
161
|
%
|
|
$
|
0.45
|
|
|
$
|
0.40
|
|
Production and ad valorem taxes
|
2,640
|
|
|
701
|
|
|
1,939
|
|
|
277
|
%
|
|
$
|
3.00
|
|
|
$
|
1.88
|
|
Depletion, depreciation, amortization and accretion
|
14,062
|
|
|
8,712
|
|
|
5,350
|
|
|
61
|
%
|
|
$
|
15.97
|
|
|
$
|
23.34
|
|
Impairment of oil and natural gas properties and dry hole costs
|
7
|
|
|
246
|
|
|
(239
|
)
|
|
(97
|
)%
|
|
NM
|
|
|
NM
|
|
Other operating expenses
|
141
|
|
|
1,466
|
|
|
(1,325
|
)
|
|
(90
|
)%
|
|
$
|
0.16
|
|
|
$
|
3.93
|
|
General and administrative (before equity-based compensation)
|
4,587
|
|
|
3,332
|
|
|
1,255
|
|
|
38
|
%
|
|
$
|
5.21
|
|
|
$
|
8.93
|
|
Total operating expenses (before equity-based compensation)
|
23,439
|
|
|
16,403
|
|
|
7,036
|
|
|
43
|
%
|
|
$
|
26.62
|
|
|
$
|
43.95
|
|
Equity-based compensation
|
408,964
|
|
|
—
|
|
|
408,964
|
|
|
|
|
|
|
|
Total operating expenses
|
$
|
432,403
|
|
|
$
|
16,403
|
|
|
$
|
416,000
|
|
|
|
|
|
|
|
_______________________________________________________________________________
NM—Not meaningful.
Lease Operating Expenses.
Our LOE varies in conjunction with our level of production, the timing of our workover expenses and variations in industry activity that cause fluctuations in service provider costs. LOE
decreased
10%
to
$1.6 million
in the first
three
months of
2017
, compared to
$1.8 million
for the same period of
2016
. The decrease primarily related to the timing of workover and maintenance costs, which decreased in the first
three
months of 2017 compared to those in the first
three
months of 2016. We expect our total 2017 second quarter LOE to increase from the levels of the first quarter. Our LOE per Boe of
$1.83
decreased significantly during the three months ended
March 31, 2017
, compared to the same period of 2016, due primarily to the
136%
increase in total production between those two periods, nearly all of which came from the addition of high-producing low-operating cost wells.
Gathering and Transportation Expenses.
Gathering and transportation expenses
increased
$0.2 million
through the first
three
months of
2017
compared to the same period of
2016
due to increased production as well as an increase in our per unit gathering and transportation expense. The period over period increase in our per unit gathering and transportation expense is due to a shift away from marketing our natural gas under percent-of-proceeds contracts toward marketing a larger portion of our natural gas under fixed fee contracts. Under percent-of-proceeds contracts, we receive a percentage of the total proceeds received by the marketer, which is net of transportation expense which includes gathering and transportation costs. Conversely, under our fixed fee natural gas marketing contracts, our gas sales revenue is determined after transporting gas to a downstream sales point and we are separately charged for the associated gathering and transportation costs.
Production and Ad Valorem Taxes.
Production and ad valorem taxes
increased
277%
between the
three
months ended
March 31, 2017
and
2016
, from
$0.7 million
in
2016
to
$2.6 million
in
2017
. The increase is due to an increase in revenues and the addition of several new high-volume wells. The effective tax rate was
6.7%
of production revenue in 2017 compared to
7.0%
in 2016.
Depletion, Depreciation, Amortization and Accretion.
DD&A expense
increased
$5.4 million
, or
61%
, through the first
three
months of
2017
compared to the same period of
2016
. The increase in DD&A was largely due to an increase in production, partially offset by a decrease in our DD&A rate. Our DD&A rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The DD&A rate per Boe
decreased
32%
to
$15.97
per Boe, compared to
$23.34
per Boe in the first
three
months of
2016
. The decrease in our DD&A rate was largely due to an increase in reserve volumes due to continued successful drilling activities, whereas the rate of increase in capitalized costs related to those drilling activities were lower than the rate of reserve increase.
Impairment of Oil and Natural Gas Properties and Dry Hole Costs.
During the first
three
months of
2017
we incurred
$7,000
of impairment costs related to the expiration of certain leases on unproved properties. During the same period in
2016
,
we recorded
$0.2 million
of impairment expense related to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties in either period of
2017
or
2016
.
Other Operating Expenses.
Other operating expenses
decreased
$1.3 million
from the first
three
months of
2016
compared to the same period of
2017
. We incurred
$0.1 million
of other operating expenses in the first
three
months of
2017
due to sales of fresh water and water disposal to third parties. During the first
three
months of
2016
, we incurred other operating expenses of
$1.5 million
, due to
$1.3 million
in delay rentals on certain unproved properties and
$0.2 million
of water sales costs.
General and Administrative and equity-based compensation.
G&A (before equity-based compensation)
increased
38%
to
$4.6 million
for the
three
months ended
March 31, 2017
, from
$3.3 million
for the same period of
2016
. The increase is primarily due to a $1.0 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the growth of our capital expenditure program and production levels. The number of our full-time employees grew from
24
at March 31,
2016
to
41
at
March 31, 2017
.
Equity-based compensation expense in the first
three
months of
2017
was
$409.0 million
, all of which related to the common stock issued to MIU holders. During the first three months of 2017, we recognized approximately
$379.0 million
of equity-based compensation expense relative to the common stock issued to MIU holders that vested upon the IPO. After the IPO, we recognized
$7.7 million
related to the common stock transferred to Management Holdco, which is subject to the terms of the Management Holdco LLC Agreement. We also recognized an additional
$22.2 million
of equity-based compensation related to awards held at Management Holdco, which were modified in conjunction with a March 2017 separation agreement of a former executive officer. We will recognize additional noncash compensation expense of approximately
$108.3 million
over the approximate three years of remaining service related to the shares held by Management Holdco.
Other Income and Expense.
The following table summarizes our other income and expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
(in thousands)
|
2017
|
|
2016
|
|
Change
|
Other income (expense):
|
|
|
|
|
Gain (loss) on commodity derivatives
|
$
|
17,042
|
|
|
$
|
(1,059
|
)
|
|
$
|
18,101
|
|
Interest expense, net
|
(711
|
)
|
|
(233
|
)
|
|
(478
|
)
|
Other, net
|
171
|
|
|
—
|
|
|
171
|
|
Total other income (expense)
|
$
|
16,502
|
|
|
$
|
(1,292
|
)
|
|
$
|
17,794
|
|
Gain (loss) on Commodity Derivatives.
Net gains and losses on our derivative instruments, as reflected in our statements of operations, are a function of fluctuations in the underlying commodity prices and the monthly settlement, if any, of the instruments. As a result, settlements on the contracts are included as a component of other income and expense as either a net gain or loss on derivative instruments. To the extent the future commodity price outlook declines between measurement periods, we will have noncash mark-to-market gains during the period. Conversely, to the extent future commodity price outlook increases between measurement periods, we will have noncash mark-to-market losses during the period.
The following table sets forth the net gain (loss) from settlements and changes in the fair value of our derivative contracts, as well as the net cash settlements (received) paid for the
three
months ended
March 31, 2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
(in thousands)
|
|
|
|
Gain (loss) on derivatives instruments, net
|
$
|
17,042
|
|
|
$
|
(1,059
|
)
|
Cash settlements of derivatives (received) paid, net
|
$
|
1,071
|
|
|
$
|
—
|
|
Interest Expense, net.
Interest expense relates to interest on our credit facility and amortization of financing costs on this facility, net of capitalized interest. During the first
three
months of
2017
and
2016
, we recorded
$0.7 million
and
$0.2 million
, respectively, of interest expense, net of capitalized interest, related to borrowings on our credit facility. Interest expense includes interest paid on the outstanding balance of the credit facility, commitment fees paid on the unused borrowing base, and amortization of debt issuance costs. The terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. The increased interest expense primarily relates to higher interest paid, as our maximum outstanding balance during the first
three
months of
2017
was $142.0 million, which we repaid in full with a portion
of the proceeds of the IPO, compared to a maximum outstanding of $35.0 million during the first
three
months of
2016
. We also had increased commitment fees due to a higher borrowing base, and higher amortization of debt issuance costs related to additional financing costs incurred throughout 2016 related to borrowing base increases.
Liquidity and Capital Resources
Historically, our predecessor’s primary sources of liquidity were capital contributions from our equity owners, borrowings under our predecessor’s credit facility and cash flows from operations. During the first
three
months of
2017
, our primary sources of liquidity were the proceeds from our IPO of
$397.0 million
, and cash flows from operations of
$21.7 million
. Historically, our predecessor’s and our primary use of cash has been for the development and acquisition of oil, natural gas and NGL properties, as well as for development of water handling and treatment 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 and production will be highly dependent on the capital resources available to us.
Capital Expenditures
Capital expenditures for oil and gas acquisitions, exploration, development and infrastructure activities are summarized below:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
(in thousands)
|
2017
|
|
2016
|
Acquisitions
|
|
|
|
Proved properties
|
$
|
—
|
|
|
$
|
—
|
|
Unproved properties
(1)
|
22,810
|
|
|
10,396
|
|
Development costs
|
91,281
|
|
|
27,325
|
|
Infrastructure costs
|
8,371
|
|
|
2,048
|
|
Exploration costs
|
6
|
|
|
1,548
|
|
Total oil and gas capital expenditures
|
$
|
122,468
|
|
|
$
|
41,317
|
|
_______________________________________________________________________________
|
|
(1)
|
Relates to acquisition of undeveloped leaseholds and oil and natural gas mineral interest leasing activity.
|
For the
three
months ended
March 31, 2017
and
2016
, our capital expenditures have been focused on the development of our properties in the Southern Delaware Basin. As of
March 31, 2017
, we had approximately
77,216
gross (
68,546
net) acres. In the first three months
2017
, we completed and began production on
seven
gross (
6.9
net) wells, all of which we operated, compared to the
two
gross (
1.9
net) wells from the same period in
2016
. At
March 31, 2017
, we were in the process of drilling
eight
gross (
7.5
net) wells and had
nine
gross (
8.1
net) wells waiting on completion.
2017 Capital Budget
Our
2017
capital budget for development of oil and gas properties and infrastructure is projected to range from
$525.0 million
to
$570.0 million
, excluding leasehold additions. Our drilling and completion and infrastructure budget is unchanged, and we expect to allocate between
$510.0 million
and
$550.0 million
of our
2017
capital budget for the drilling and completion of operated and non-operated wells. Additionally, we expect to allocate between
$15.0 million
and
$20.0 million
of our
2017
capital budget for water infrastructure costs, excluding any potential additions for surface acreage. Based on our
2017
capital budget, we anticipate that we will spud approximately
54
to
58
gross operated wells, and approximately
11
to
15
gross non-operated wells. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.
Because we operate a high percentage of our acreage, capital expenditure amounts and timing are largely discretionary and within our control. We determine our capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped
reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and additional borrowing capacity under our credit facility to execute our planned
2017
capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. If we require additional capital for capital expenditures, acquisitions or other reasons, we may seek such capital through borrowings under our credit facility, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.
Working Capital
Our working capital, which we define as current assets minus current liabilities, fluctuates primarily as a result of our realized commodity prices, increases or decreases in our production volumes, changes in receivables and payables related to our operating and development of oil and natural gas activities, changes in our hedging activities and changes in our cash and cash equivalents. At
March 31, 2017
, our working capital was a
surplus
of
$148.7 million
, compared to a
deficit
of
$31.0 million
at
December 31, 2016
.
We may incur additional working capital deficits in the future due to liabilities that accrue related to our drilling program. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled approximately
$198.8 million
and
$11.7 million
at
March 31, 2017
and
December 31, 2016
, respectively. We expect that our existing cash balances, cash flows from operating activities and availability under our credit facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, and commodity prices for our oil and natural gas production will be the largest variables affecting our working capital.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
(in thousands)
|
2017
|
|
2016
|
Net cash provided by operating activities
|
$
|
21,701
|
|
|
$
|
5,064
|
|
Net cash used in investing activities
|
$
|
(100,684
|
)
|
|
$
|
(34,948
|
)
|
Net cash provided by financing activities
|
$
|
266,065
|
|
|
$
|
31,574
|
|
Operating Activities.
Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. The
$16.6 million
increase
in net cash provided by operating activities for the first
three
months of
2017
compared to
2016
primarily resulted due to a period-over-period
increase
in revenues. This was partially offset by higher operating costs due to increased production and net cash payments for settlements of derivatives, and higher operating costs primarily due to increased production.
Investing Activities.
For the first
three
months of
2017
, net cash flow used in investing activities was
$100.7 million
,
an increase
of
$65.7 million
(
188%
) from
$34.9 million
for the same period of
2016
. In the first
three
months of
2017
, net cash used for investing activities included investments in developing our acreage of
$74.3 million
and leasehold and acquisition costs of
$25.6 million
. In the first
three
months of
2016
, net cash used for investing activities included
$17.0 million
and
$17.3 million
for the acquisition and development of oil and natural gas properties, respectively.
Financing Activities.
Net cash provided by financing activities during the first
three
months of
2017
was primarily due to
$399.1 million
of net proceeds from the sale of common stock in our IPO, which was partially offset by net repayments on our credit facility of $132.0 million. Net cash provided by financing activities in
2016
included
$16.6 million
of cash provided by equity issuances and
$15.0 million
of borrowings under our credit facility.
Credit Facility
On June 19, 2015, our predecessor entered into a credit agreement that provided for a senior secured revolving credit facility with an aggregate commitment of $500.0 million (subject to the then-effective borrowing base). In January 2017, this credit facility was amended, which increased the aggregate principal commitment to $1.0 billion and the borrowing base to
$180.0 million
. In connection with our IPO, we, as parent guarantor, and our predecessor, as borrower, entered into an amended and restated credit facility. The amended and restated credit facility matures on February 1, 2022. After giving effect to such amendment and restatement, the borrowing base under the amended and restated credit facility remained at
$180.0 million
. Also in connection with the IPO, we fully repaid the outstanding borrowings under the credit facility of $142.0 million.
The amount available to be borrowed under our amended and restated credit facility is subject to a borrowing base that is redetermined semiannually by each April 1 and October 1 by the lenders at their sole discretion. Additionally, at our option, we may request up to two additional redeterminations per year, to be effective on or about January 1 and July 1, respectively. The borrowing base depends on, among other things, the volumes of our proved reserves and estimated cash flows from these reserves and our commodity hedge positions as well as any other outstanding debt. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, we could be required to immediately repay a portion of the debt outstanding under our credit agreement. The most recent redetermination was completed in April 2017, which resulted in an increase to the borrowing base from
$180.0 million
to
$250.0 million
, which as of the date of this filing remains undrawn.
We pay a commitment fee on unused amounts of our amended and restated credit facility of
0.50%
per annum. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
Our credit agreement contains restrictive covenants that limit our ability to, among other things:
|
|
•
|
incur additional indebtedness;
|
|
|
•
|
merge or consolidate with another entity;
|
|
|
•
|
enter into transactions with affiliates;
|
|
|
•
|
hedge interest rates; and
|
|
|
•
|
engage in certain other transactions without the prior consent of the lenders.
|
At
March 31, 2017
, our credit agreement also requires us to maintain compliance with the following financial ratios:
|
|
•
|
a current ratio, which is the ratio of our consolidated current assets (including unused commitments under our credit facility and excluding noncash assets related to asset retirement obligations and derivatives) to our consolidated current liabilities (excluding the current portion of long-term debt under our credit agreement and noncash liabilities related to asset retirement obligations and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and
|
|
|
•
|
a leverage ratio, which is the ratio of our consolidated Debt (as defined in our credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in our credit agreement) to EBITDAX (as defined in our credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0.
|
As of
March 31, 2017
, we were in compliance with all financial covenants.
The amended and restated credit facility permits us to hedge up to the greater of 85% of proved reserves and 75% of our reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years.
Contractual Obligations
A summary of our contractual obligations as of
March 31, 2017
is provided in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remainder
|
|
Payments Due by Period for the Year Ending December 31,
|
(in thousands)
|
of 2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
Credit facility
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Operating leases
(2)
|
745
|
|
|
555
|
|
|
6
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,307
|
|
Service and purchase contracts
(3)
|
902
|
|
|
9
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
912
|
|
Rig contracts
(4)
|
13,577
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,577
|
|
Total
|
$
|
15,224
|
|
|
$
|
564
|
|
|
$
|
7
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15,796
|
|
_______________________________________________________________________________
|
|
(1)
|
This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on our credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. As of
March 31, 2017
, we had
nothing
outstanding under our amended and restated credit facility and
$180.0 million
of borrowing capacity available.
|
|
|
(2)
|
Primarily relates to the lease of our corporate offices.
|
|
|
(3)
|
Primarily relates to our obligation to purchase lease automatic custody transfer units in conjunction with oil gathering for current and future wells.
|
|
|
(4)
|
Relates to
six
drilling rig contracts entered into as of
March 31, 2017
. If we were to terminate these contracts at
March 31, 2017
, we would be required to pay early termination penalties of approximately
$8.2 million
.
|
Off-Balance Sheet Arrangements
We had no material off-balance sheet arrangements as of
March 31, 2017
. Please read Note
10
,
Commitments and Contingencies
, included in the notes to our consolidated and combined financial statements included in this Quarterly Report on Form 10-Q, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.
Critical Accounting Policies and Estimates
Our management makes a number of significant estimates, assumptions and judgments in the preparation of our financial statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our
2016
Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in our accounting for successful efforts method of accounting for oil and natural gas activities, impairment of oil and natural gas properties, oil and natural gas reserve quantities, derivative instruments, and asset retirement obligations. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to our consolidated and combined financial statements contained in this Quarterly Report on Form 10-Q. The application of our critical accounting policies may require management to make judgments and estimates about the amounts reflected in the consolidated and combined financial statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.
Equity-Based Compensation
In connection with the IPO, we adopted the Jagged Peak Energy Inc. 2017 Long Term Incentive Plan (the “Plan”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. See “Part III, Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2016 for additional information related to the Plan.
We recognize compensation cost related to all equity-based awards in the financial statements based on their estimated grant-date fair value. We may grant various types of equity-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions) and restricted stock units (including awards with service-based vesting and market condition-based vesting provisions). Service-based restricted stock units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock units are based on the grant-date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period, and forfeitures are recognized as they occur.
Income Taxes
We are a subchapter C-corporation and are subject to U.S. federal and state income taxes. Income taxes are accounted for under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which we operate for the year in which those temporary differences are expected to be recovered or settled. We classify all deferred tax assets and liabilities as noncurrent. We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on technical merits, that the position will be sustained upon examination. Deferred tax assets are then reduced by a valuation allowance if we believe it is more-likely-than-not such deferred tax assets will not be realized.
Recent Accounting Pronouncements
Please refer to Note 2,
Significant Accounting Policies and Related Matters – Recent Accounting Pronouncements
, to the consolidated and combined financial statements included in this Quarterly Report on Form 10-Q for a discussion of recent accounting pronouncements and their anticipated effect on our business.