NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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1.
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BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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Basis of Presentation
These consolidated financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods reported in all material respects, on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal, recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s most recent annual report on Form 10-K. Results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results expected for the full year.
Statements of Cash Flows
During the third quarter of 2019, the Company identified that certain activities were misclassified between cash flows from operating activities and cash flows from investing activities. These activities had been included in accounts payable, accrued liabilities and other and presented as cash flows from operating activities while they should have been presented as additions to oil and natural gas properties in cash flows from investing activities. The Company corrected the previously presented statements of cash flows for these additions and in doing so, for the nine months ended September 30, 2018, the consolidated statements of cash flows and the condensed consolidating statements of cash flows were adjusted to increase net cash flows provided by operating activities by $21.8 million with a corresponding increase in net cash flows used in investing activities. The Company has evaluated the effect of the incorrect presentation, both qualitatively and quantitatively, and concluded that it did not have a material impact on any previously filed annual or quarterly consolidated financial statements.
Recently Issued Accounting Pronouncements
In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. Subsequent to ASU 2016-02, the FASB issued several related ASU’s to clarify the application of the lease standard. The Company adopted the new standard as of January 1, 2019 on a prospective basis using the simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 13 for further discussion of the lease standard.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted. The Company is in the process of designing processes and controls needed to comply with the requirements of the new standard. Although the standard will have an impact, the Company does not currently anticipate the ASU to have a material effect on its consolidated financial statements and related disclosures.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.
In August 2018, the FASB also issued ASU No. 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.
In November 2018, the FASB issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.
In July 2019, the FASB issued ASU No. 2019-07, Codification Updates to SEC Sections, Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates. This ASU amends various SEC sections within the FASB Codification to align with the updated requirements of certain SEC final rules and includes miscellaneous updates to agree the language in the Codification to the electronic Code of Federal Regulations. ASU No. 2019-07 is effective upon issuance, and the Company has adopted the changes with no material impacts.
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2.
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PROPERTY AND EQUIPMENT
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The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of September 30, 2019 and December 31, 2018 are as follows:
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September 30, 2019
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December 31, 2018
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(In thousands)
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Oil and natural gas properties
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$
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10,551,713
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$
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10,026,836
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Other depreciable property and equipment
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90,712
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87,146
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Land
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5,521
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5,521
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Total property and equipment
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10,647,946
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10,119,503
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Accumulated depletion, depreciation, amortization and impairment
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(5,063,413
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)
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(4,640,098
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)
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Property and equipment, net
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$
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5,584,533
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$
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5,479,405
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Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At September 30, 2019, the net book value of the Company's oil and gas properties, less related deferred income taxes, was above the calculated ceiling as a result of reduced commodity prices for the period leading up to September 30, 2019. As a result, the Company was required to record an impairment of its oil and natural gas properties under the full cost method of accounting in the amount of $35.6 million for the three and nine months ended September 30, 2019. No impairment was required for oil and natural gas properties for the three and nine months ended September 30, 2018. Additional impairments of oil and natural gas properties are expected to occur in upcoming quarters should commodity prices continue below the average of the previous 12 months. However, the amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs.
Included in oil and natural gas properties at September 30, 2019 is the cumulative capitalization of $229.6 million in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to
the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $9.8 million and $26.3 million for the three and nine months ended September 30, 2019, respectively, and $10.6 million and $28.8 million for the three and nine months ended September 30, 2018, respectively.
The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $1.01 and $0.94 per Mcfe for the nine months ended September 30, 2019 and 2018, respectively.
The following table summarizes the Company’s non-producing properties excluded from amortization by area at September 30, 2019:
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September 30, 2019
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(In thousands)
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Utica
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$
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1,464,803
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MidContinent
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1,349,191
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Other
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340
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$
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2,814,334
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At December 31, 2018, approximately $2.9 billion of non-producing leasehold costs was not subject to amortization.
The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three to five years. However, the majority of the Company’s non-producing leases in the Utica Shale have five-year extension terms which could extend this time frame beyond five years.
Divestitures
In December of 2018, the Company entered into an agreement to sell its non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions, with an effective date of August 15, 2018. The Company received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 9 for further discussion of the contingent consideration arrangement, which was determined to be an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date.
Asset Retirement Obligation
A reconciliation of the Company’s asset retirement obligation for the nine months ended September 30, 2019 and 2018 is as follows:
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September 30, 2019
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September 30, 2018
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(In thousands)
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Asset retirement obligation, beginning of period
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$
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79,952
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$
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75,100
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Liabilities incurred
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5,769
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1,468
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Liabilities settled
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(117
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(719
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Liabilities removed due to divestitures
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(30,035
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)
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—
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Accretion expense
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3,173
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3,056
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Revisions in estimated cash flows
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1,077
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(374
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)
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Asset retirement obligation as of end of period
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59,819
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78,531
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Less current portion
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—
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120
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Asset retirement obligation, long-term
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$
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59,819
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$
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78,411
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Investments accounted for by the equity method consist of the following as of September 30, 2019 and December 31, 2018:
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Carrying value
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Loss (income) from equity method investments
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Approximate ownership %
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September 30, 2019
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December 31, 2018
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Three months ended September 30,
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Nine months ended September 30,
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2019
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2018
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2019
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2018
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(In thousands)
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Investment in Tatex Thailand II, LLC
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23.5
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%
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$
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—
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$
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—
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$
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—
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$
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(137
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$
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(2,085
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$
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(241
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)
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Investment in Grizzly Oil Sands ULC
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24.9999
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%
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49,546
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44,259
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41
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275
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380
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833
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Investment in Timber Wolf Terminals LLC(1)
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—
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%
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—
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—
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—
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—
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—
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536
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Investment in Windsor Midstream LLC
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22.5
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%
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39
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39
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—
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—
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—
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(9
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Investment in Mammoth Energy Services, Inc.
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21.8
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%
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24,377
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191,823
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43,041
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(12,996
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)
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166,096
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(35,708
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Investment in Strike Force Midstream LLC(2)
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—
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%
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—
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—
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—
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—
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—
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(693
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$
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73,962
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$
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236,121
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$
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43,082
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$
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(12,858
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$
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164,391
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$
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(35,282
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(1)
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On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"). See below under Timber Wolf Terminals LLC for information regarding the subsequent dissolution of Timber Wolf.
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(2)
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On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream LLC ("Strike Force") to EQT Midstream Partners, LP. See below under Strike Force Midstream LLC for information regarding this transaction.
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The tables below summarize financial information for the Company’s equity investments as of September 30, 2019 and December 31, 2018.
Summarized balance sheet information:
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September 30, 2019
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December 31, 2018
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(In thousands)
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Current assets
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$
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427,643
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$
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471,733
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Noncurrent assets
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$
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1,309,729
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$
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1,302,488
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Current liabilities
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$
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130,465
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$
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239,975
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Noncurrent liabilities
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$
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176,145
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$
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94,575
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Summarized results of operations:
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Three months ended September 30,
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Nine months ended September 30,
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2019
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2018
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2019
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2018
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(In thousands)
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Gross revenue
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$
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113,417
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$
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384,043
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$
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557,375
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$
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1,451,580
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Net (loss) income
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$
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(35,730
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)
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$
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68,414
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$
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(15,046
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)
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$
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181,884
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Tatex Thailand II, LLC
The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex II"). Tatex II held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field. The Company received $2.1 million in distributions from Tatex II during the nine months ended September 30, 2019, of which $1.9 million related to proceeds from the sale of its interest in APICO.
Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.9999% interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. (“Oil Sands”). As of September 30, 2019, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company reviewed its investment in Grizzly for impairment at September 30, 2019 and 2018 and determined no impairment was required. If commodity prices decline in the future however, impairment of the Company's investment in Grizzly may be necessary. During the nine months ended September 30, 2019, Gulfport paid $0.4 million in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was decreased by a $2.0 million foreign currency translation loss and increased by a $5.2 million foreign currency translation gain for the three and nine months ended September 30, 2019, respectively. The Company's investment in Grizzly was increased by a $2.9 million foreign currency translation gain and decreased by a $5.7 million foreign currency translation loss for the three and nine months ended September 30, 2018, respectively.
Timber Wolf Terminals LLC
During 2012, the Company invested in Timber Wolf. Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. Timber Wolf was dissolved in 2018.
Windsor Midstream LLC
At September 30, 2019, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received no distributions from Midstream during the nine months ended September 30, 2019.
The Company has determined that Midstream is a variable interest entity ("VIE") but that the Company is not the primary beneficiary because it does not have a controlling financial interest in Midstream. This entity is considered a VIE because the limited partners lack substantive kick-out or participating rights over the general partner. The general partner has power to direct the activities that most significantly impact Midstream's economic performance. The Company accounts for its investment in
VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations.
Mammoth Energy Services, Inc.
At September 30, 2019, the Company owned 9,829,548 shares, or approximately 21.8%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The Company reviewed its investment in Mammoth Energy as of September 30, 2019 for impairment based on certain qualitative and quantitative factors. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was indicated. This resulted in recording an impairment loss of $35.5 million and $160.8 million for the three and nine months ended September 30, 2019, which is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. If Mammoth Energy's common stock continues to trade below the Company's carrying value for a prolonged period of time, further impairment of the Company's investment in Mammoth Energy may be necessary. The Company’s investment in Mammoth Energy was decreased by a $0.1 million foreign currency loss and increased by a $0.1 million foreign currency gain resulting from Mammoth Energy's foreign subsidiary for the three and nine months ended September 30, 2019, respectively. The Company’s investment in Mammoth Energy was increased by a $0.1 million foreign currency gain and decreased by a $0.2 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the three and nine months ended September 30, 2018, respectively. During the nine months ended September 30, 2019, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of $0.125 per share dividends in February 2019 and May 2019. The approximate fair value of the Company's investment in Mammoth Energy's common stock at September 30, 2019 was $24.4 million based on the quoted market price of Mammoth Energy's common stock. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.
Strike Force Midstream LLC
In February 2016, the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), then a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through Strike Force. In 2017, Rice was acquired by EQT Corporation ("EQT"). The Company owned a 25% interest in Strike Force, which was sold to EQT Midstream Partners, LP in May 2018. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.
Long-term debt consisted of the following items as of September 30, 2019 and December 31, 2018:
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September 30, 2019
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December 31, 2018
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(In thousands)
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Revolving credit agreement(1)
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$
|
135,000
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|
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$
|
45,000
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|
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6.625% senior unsecured notes due 2023
|
340,000
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|
|
350,000
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|
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6.000% senior unsecured notes due 2024
|
630,796
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|
|
650,000
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|
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6.375% senior unsecured notes due 2025
|
577,268
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|
|
600,000
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|
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6.375% senior unsecured notes due 2026
|
397,529
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|
|
450,000
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|
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Net unamortized debt issuance costs(2)
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(26,052
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)
|
|
(30,733
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)
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Construction loan
|
22,650
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|
|
23,149
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|
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Less: current maturities of long term debt
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(622
|
)
|
|
(651
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)
|
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Debt reflected as long term
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$
|
2,076,569
|
|
|
$
|
2,086,765
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(1) The Company has entered into a senior secured revolving credit facility, as amended (the "revolving credit facility"), with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. On June 3, 2019, the Company further amended its revolving credit facility to, among other things, allow the Company to designate certain of its subsidiaries
as unrestricted subsidiaries and to include LIBOR replacement provisions. Additionally, the borrowing base was reaffirmed at $1.4 billion, and the Company’s elected commitment amount remained at $1.0 billion.
As of September 30, 2019, $135.0 million was outstanding under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $248.6 million letters of credit, was $616.4 million. The Company’s wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.
At September 30, 2019, amounts borrowed under the revolving credit facility bore interest at a weighted average rate of 3.52%.
The Company was in compliance with its financial covenants under the revolving credit facility at September 30, 2019.
(2) Loan issuance costs related to the 6.625% Senior Notes due 2023 (the "2023 Notes"), the 6.000% Senior Notes due 2024 (the "2024 Notes"), the 6.375% Senior Notes due 2025 (the "2025 Notes") and the 6.375% Senior Notes due 2026 (the "2026 Notes") (collectively the “Notes”) have been presented as a reduction to the principal amount of the Notes. At September 30, 2019, total unamortized debt issuance costs were $3.6 million for the 2023 Notes, $7.5 million for the 2024 Notes, $10.8 million for the 2025 Notes and $4.0 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement were $0.1 million at September 30, 2019.
The Company capitalized approximately $1.0 million and $2.8 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2019, respectively. The Company capitalized approximately $1.6 million and $4.0 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2018, respectively.
Debt Repurchases
During the three months ended September 30, 2019, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $104.4 million aggregate principal amount of its outstanding Notes for $80.3 million. This included approximately $10.0 million principal amount of the 2023 Notes, $19.2 million principal amount of the 2024 Notes, $22.7 million principal amount of the 2025 Notes, and $52.5 million principal amount of the 2026 Notes. The Company recognized a $23.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt. This gain is included in gain on debt extinguishment in the accompanying consolidated statements of operations.
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5.
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COMMON STOCK AND CHANGES IN CAPITALIZATION
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Stock Repurchase Program
In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the Company's outstanding stock during 2018. In May 2018, the Company's board of directors authorized the expansion of its stock repurchase program, authorizing the Company to acquire up to an additional $100 million of its outstanding common stock during 2018 for a total of up to $200 million. The repurchase program did not require the Company to acquire any specific number of shares. This repurchase program was authorized to extend through December 31, 2018 and the Company repurchased 20.7 million shares of common stock in 2018 for $200.0 million in aggregate consideration.
In January 2019, the board of directors of the Company approved a new stock repurchase program to acquire a portion of the Company's outstanding common stock within a 24 month period. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program is authorized to extend through December 31, 2020 and may be suspended, modified, extended or discontinued by the board of directors at any time. The Company did not repurchase any shares under the program during the three months ended September 30, 2019, and repurchased approximately 3.8 million shares for a cost of approximately $30.0 million during the nine months ended September 30, 2019. Additionally, during each of the three and nine months ended September 30, 2019, the Company repurchased approximately 0.1 million shares for a cost of approximately $0.1 million and $0.7 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. All repurchased shares have been canceled and returned to the status of authorized but unissued shares.
|
|
|
|
6.
|
STOCK-BASED COMPENSATION
|
The Company has granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan ("2019 Plan"), as discussed below. During the three and nine months ended September 30, 2019, the Company’s stock-based compensation cost was $2.7 million and $8.3 million, respectively, of which the Company capitalized $1.1 million and $3.3 million, respectively, relating to its exploration and development efforts. During the three and nine months ended September 30, 2018, the Company's stock-based compensation cost was $3.6 million and $9.7 million, respectively, of which the Company capitalized $1.4 million and $3.9 million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.
The following table summarizes restricted stock unit activity for the nine months ended September 30, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Unvested
Restricted Stock Units
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Number of
Unvested
Performance Vesting Restricted Stock Units
|
|
Weighted
Average
Grant Date
Fair Value
|
|
Unvested shares as of January 1, 2019
|
1,535,811
|
|
|
$
|
11.57
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Granted
|
4,011,073
|
|
|
3.74
|
|
|
2,009,144
|
|
|
2.85
|
|
|
Vested
|
(674,374
|
)
|
|
12.86
|
|
|
—
|
|
|
—
|
|
|
Forfeited
|
(289,610
|
)
|
|
7.83
|
|
|
(112,742
|
)
|
|
1.98
|
|
|
Unvested shares as of September 30, 2019
|
4,582,900
|
|
|
$
|
4.76
|
|
|
1,896,402
|
|
|
$
|
2.91
|
|
Restricted Stock Units
Restricted stock units awarded under the 2019 Plan generally vest over a period of one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of September 30, 2019 related to restricted stock units was $19.0 million. The expense is expected to be recognized over a weighted average period of 2.28 years.
Performance Vesting Restricted Stock Units
During the nine months ended September 30, 2019, the Company awarded performance vesting units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on relative total shareholder return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR of the companies in the Company’s designated peer group at the end of the performance period. Awards will be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately two years. The risk-free interest rates were based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a range of risk-free interest rates of 1.56% to 2.42% and a range of expected volatilities of 29.1% to 85.1% to estimate the fair value of performance vesting units granted during the nine months ended September 30, 2019. Unrecognized compensation expense as of September 30, 2019 related to performance vesting restricted shares was $4.9 million. The expense is expected to be recognized over a weighted average period of 2.64 years.
Reconciliations of the components of basic and diluted net income per common share are presented in the tables below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2019
|
|
2018
|
|
|
Loss
|
|
Shares
|
|
Per
Share
|
|
Income
|
|
Shares
|
|
Per
Share
|
|
|
(In thousands, except share data)
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
$
|
(48,752
|
)
|
|
159,548,477
|
|
|
$
|
(0.31
|
)
|
|
$
|
95,150
|
|
|
173,057,538
|
|
|
$
|
0.55
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and awards
|
—
|
|
|
—
|
|
|
|
|
—
|
|
|
247,376
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
$
|
(48,752
|
)
|
|
159,548,477
|
|
|
$
|
(0.31
|
)
|
|
$
|
95,150
|
|
|
173,304,914
|
|
|
$
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2019
|
|
2018
|
|
|
Income
|
|
Shares
|
|
Per
Share
|
|
Income
|
|
Shares
|
|
Per
Share
|
|
|
(In thousands, except share data)
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
248,446
|
|
|
160,553,796
|
|
|
$
|
1.55
|
|
|
$
|
296,559
|
|
|
175,776,312
|
|
|
$
|
1.69
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and awards
|
—
|
|
|
4,266,206
|
|
|
|
|
—
|
|
|
664,149
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
248,446
|
|
|
164,820,002
|
|
|
$
|
1.51
|
|
|
$
|
296,559
|
|
|
176,440,461
|
|
|
$
|
1.68
|
|
There were 2,073,638 shares of common stock that were considered anti-dilutive for the three months ended September 30, 2019. There were no potential shares of common stock that were considered anti-dilutive for the nine months ended September 30, 2019 or the three and nine months ended September 30, 2018.
|
|
|
|
8.
|
COMMITMENTS AND CONTINGENCIES
|
Firm Transportation and Sales Commitments
The table below presents the firm sales commitments by year:
|
|
|
|
|
|
|
|
|
|
(MMBtu per day)
|
|
Remaining 2019
|
|
424,000
|
|
|
2020
|
|
314,000
|
|
|
2021
|
|
192,000
|
|
|
2022
|
|
70,000
|
|
|
2023
|
|
17,000
|
|
|
Thereafter
|
|
—
|
|
|
Total
|
|
1,017,000
|
|
The table below presents the firm transportation commitments by year:
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Remaining 2019
|
|
$
|
65,763
|
|
|
2020
|
|
287,627
|
|
|
2021
|
|
286,665
|
|
|
2022
|
|
286,665
|
|
|
2023
|
|
282,981
|
|
|
Thereafter
|
|
2,410,866
|
|
|
Total
|
|
$
|
3,620,567
|
|
Other Commitments
Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective August 3, 2018, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses through 2021. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred $0.02 million and $0.4 million in non-utilization fees under this agreement during the three and nine months ended September 30, 2019, respectively. The Company incurred $1.3 million and $1.5 million in non-utilization fees under this agreement during the three and nine months ended September 30, 2018.
Future minimum commitments under this agreement at September 30, 2019 are:
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Remaining 2019
|
$
|
6,000
|
|
|
2020
|
24,000
|
|
|
2021
|
24,000
|
|
|
Total
|
$
|
54,000
|
|
Litigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is
indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.
The Company, along with a number of other oil and gas companies, has been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.
In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of the Company’s legacy Louisiana properties, filed an action against the Company and a number of other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of the Company’s Louisiana properties and seeks unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest.
In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by the Company, and its significant stockholders, including the Company, in the United States District Court for the Western District of Oklahoma. The complaint alleges, among other things, that the members of Mammoth Energy’s board of directors breached their fiduciary duties and violated the Securities Exchange Act of 1934, as amended, in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.
In October 2019, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed an action against the Company in the District Court of Grady County Oklahoma. The suit alleges that the Company underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.
In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against the Company in the District Court of Grady County, Oklahoma. The suit alleges that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.
These cases are still in their early stages. As a result, the Company has not had the opportunity to evaluate the allegations made in the plaintiffs' complaints and intends to vigorously defend the suits.
The Company filed an action against TH Exploration, LLC ("TH") in Tarrant County, Texas. The suit alleges breach of purchase and sale agreement providing for the Company's disposition of certain oil and gas properties in Ohio to TH. The Company is seeking specific performance, related to TH's obligations to close the transaction and tender the purchase price, along with any additional relief available to the Company.
SEC Investigation
The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. The Company has fully cooperated and intends to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability
with respect to this matter, the Company believes that the outcome of this matter will not have a material effect on the Company’s business, financial condition or results of operations.
Business Operations
The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.
The Company received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 12 locations in Ohio. The first FOV for one site was dated December 11, 2013. Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019. The Company has exchanged information with the USEPA and is engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
|
|
|
|
9.
|
DERIVATIVE INSTRUMENTS
|
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments
The Company seeks to reduce its exposure to unfavorable changes in natural gas, oil and natural gas liquids ("NGLs") prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective natural gas, oil and NGLs prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production.
Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural gas, the NYMEX West Texas Intermediate for oil and Mont Belvieu for propane, pentane and ethane. Below is a summary of the Company’s open fixed price swap positions as of September 30, 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted
Average Price
|
|
Remaining 2019
|
NYMEX Henry Hub
|
1,380,000
|
|
|
$
|
2.81
|
|
|
2020
|
NYMEX Henry Hub
|
519,000
|
|
|
$
|
2.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location
|
Daily Volume
(Bbls/day)
|
|
Weighted
Average Price
|
|
Remaining 2019
|
NYMEX WTI
|
6,000
|
|
|
$
|
60.81
|
|
|
2020
|
NYMEX WTI
|
6,000
|
|
|
$
|
59.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location
|
Daily Volume
(Bbls/day)
|
|
Weighted
Average Price
|
|
Remaining 2019
|
Mont Belvieu C2
|
1,000
|
|
|
$
|
18.48
|
|
|
Remaining 2019
|
Mont Belvieu C3
|
4,000
|
|
|
$
|
29.02
|
|
|
Remaining 2019
|
Mont Belvieu C5
|
1,000
|
|
|
$
|
53.71
|
|
The Company sold call options in exchange for a premium, and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020 listed above. Each call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.
|
|
|
|
|
|
|
|
|
|
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted Average Price
|
|
Remaining 2019
|
NYMEX Henry Hub
|
30,000
|
|
|
$
|
3.10
|
|
|
2022
|
NYMEX Henry Hub
|
628,000
|
|
|
$
|
2.90
|
|
|
2023
|
NYMEX Henry Hub
|
628,000
|
|
|
$
|
2.90
|
|
For a portion of the natural gas fixed price swaps listed above, the counterparty had the option to extend the original terms for an additional twelve months for the period of January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is included in the natural gas fixed price swaps listed above.
In addition, the Company entered into natural gas basis swap positions. As of September 30, 2019, the Company had the following natural gas basis swap positions open:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulfport Pays
|
Gulfport Receives
|
Daily Volume (MMBtu/day)
|
|
Weighted Average Fixed Spread
|
|
Remaining 2019
|
Transco Zone 4
|
NYMEX Plus Fixed Spread
|
60,000
|
|
|
$
|
(0.05
|
)
|
|
2020
|
Transco Zone 4
|
NYMEX Plus Fixed Spread
|
60,000
|
|
|
$
|
(0.05
|
)
|
|
2020
|
Fixed Spread
|
ONEOK Minus NYMEX
|
10,000
|
|
|
$
|
(0.54
|
)
|
Contingent Consideration Arrangement
The purchase and sale agreement for the sale of the Company's non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles the Company to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture. See below for threshold and potential payment amounts.
|
|
|
|
|
|
|
|
|
Period
|
Threshold(1)
|
Payment to be received(2)
|
|
July 2020 - June 2021
|
Greater than or equal to $60.65
|
$
|
150,000
|
|
|
|
Between $52.62 - $60.65
|
Calculated Value(3)
|
|
|
|
Less than or equal to $52.62
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media.
|
|
(2)
|
Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month.
|
|
(3)
|
If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03.
|
Balance Sheet Presentation
The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at September 30, 2019 and December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
|
(In thousands)
|
|
Commodity derivative instruments
|
$
|
134,511
|
|
|
$
|
21,352
|
|
|
Contingent consideration arrangement
|
60
|
|
|
—
|
|
|
Total short-term derivative instruments - asset
|
$
|
134,571
|
|
|
$
|
21,352
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
23,375
|
|
|
$
|
—
|
|
|
Contingent consideration arrangement
|
44
|
|
|
—
|
|
|
Total long-term derivative instruments - asset
|
$
|
23,419
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Total short-term derivative instruments - liability
|
$
|
429
|
|
|
$
|
20,401
|
|
|
|
|
|
|
|
Total long-term derivative instruments - liability
|
$
|
72,040
|
|
|
$
|
13,992
|
|
Gains and Losses
The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGLs derivatives in the accompanying consolidated statements of operations for the three and nine months ended September 30, 2019 and 2018.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on derivative instruments
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
|
Natural gas derivatives
|
$
|
11,731
|
|
|
$
|
14,101
|
|
|
$
|
147,774
|
|
|
$
|
(26,789
|
)
|
|
Oil derivatives
|
12,736
|
|
|
(11,610
|
)
|
|
24,153
|
|
|
(45,176
|
)
|
|
NGLs derivatives
|
3,641
|
|
|
(12,154
|
)
|
|
7,276
|
|
|
(24,772
|
)
|
|
Contingent consideration arrangement
|
(1,034
|
)
|
|
—
|
|
|
(1,034
|
)
|
|
—
|
|
|
Total
|
$
|
27,074
|
|
|
$
|
(9,663
|
)
|
|
$
|
178,169
|
|
|
$
|
(96,737
|
)
|
Offsetting of Derivative Assets and Liabilities
As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value.
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|
|
|
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|
|
|
|
|
|
|
|
|
As of September 30, 2019
|
|
|
Gross Assets (Liabilities)
|
|
Gross Amounts
|
|
|
|
|
Presented in the
|
|
Subject to Master
|
|
Net
|
|
|
Consolidated Balance Sheets
|
|
Netting Agreements
|
|
Amount
|
|
|
(In thousands)
|
|
Derivative assets
|
$
|
157,990
|
|
|
$
|
(72,469
|
)
|
|
$
|
85,521
|
|
|
Derivative liabilities
|
$
|
(72,469
|
)
|
|
$
|
72,469
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
|
Gross Assets (Liabilities)
|
|
Gross Amounts
|
|
|
|
|
Presented in the
|
|
Subject to Master
|
|
Net
|
|
|
Consolidated Balance Sheets
|
|
Netting Agreements
|
|
Amount
|
|
|
(In thousands)
|
|
Derivative assets
|
$
|
21,352
|
|
|
$
|
(19,289
|
)
|
|
$
|
2,063
|
|
|
Derivative liabilities
|
$
|
(34,393
|
)
|
|
$
|
19,289
|
|
|
$
|
(15,104
|
)
|
Concentration of Credit Risk
By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company’s derivative contracts are with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.
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10.
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FAIR VALUE MEASUREMENTS
|
The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories:
Level 1 – Quoted prices in active markets for identical assets and liabilities.
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 – Significant inputs to the valuation model are unobservable.
Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of September 30, 2019 and December 31, 2018:
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|
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|
|
|
|
|
|
|
September 30, 2019
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
|
Assets:
|
|
|
|
|
|
|
Derivative Instruments
|
$
|
—
|
|
|
$
|
157,990
|
|
|
$
|
—
|
|
|
Liabilities:
|
|
|
|
|
|
|
Derivative Instruments
|
$
|
—
|
|
|
$
|
72,469
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
|
Assets:
|
|
|
|
|
|
|
Derivative Instruments
|
$
|
—
|
|
|
$
|
21,352
|
|
|
$
|
—
|
|
|
Liabilities:
|
|
|
|
|
|
|
Derivative Instruments
|
$
|
—
|
|
|
$
|
34,393
|
|
|
$
|
—
|
|
The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
The fair value of the Company's investment in Mammoth Energy as of September 30, 2019 was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares.
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 2 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the nine months ended September 30, 2019 were approximately $5.8 million.
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|
11.
|
FAIR VALUE OF FINANCIAL INSTRUMENTS
|
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's construction loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.
At September 30, 2019, the carrying value of the outstanding debt represented by the Notes was approximately $1.9 billion, including the unamortized debt issuance cost of approximately $3.6 million related to the 2023 Notes, approximately $7.5 million related to the 2024 Notes, approximately $10.8 million related to the 2025 Notes and approximately $4.0 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $1.4 billion at September 30, 2019.
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|
|
|
12.
|
REVENUE FROM CONTRACTS WITH CUSTOMERS
|
Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGLs. Sales of natural gas, oil and condensate and NGLs are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at the time control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less, and the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.
Contract Balances
Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $112.7
million and $210.2 million as of September 30, 2019 and December 31, 2018, respectively, and are reported in accounts receivable - oil and natural gas sales on the consolidated balance sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.
Prior-Period Performance Obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For the nine months ended September 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Effective January 1, 2019, the Company adopted ASU No. 2016-02, Leases (Topic 842). The new standard supersedes the previous lease guidance by requiring lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The Company adopted the new standard on a prospective basis using the simplified transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting right-of-use assets and corresponding lease liabilities recognized by the Company on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations exceeding one year. No cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The Company elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications.
Nature of Leases
The Company has operating leases associated with drilling rig commitments, pressure pumping services, field offices and other equipment with remaining lease terms with contractual durations in excess of one year. Short-term leases that have an initial term of one year or less are not capitalized.
The Company has entered into contracts for drilling rigs with third parties to ensure rig availability in its key operating areas. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the evaluation that the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of one to two years and expire at various dates through 2021. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.
Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective July 1, 2018, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company through 2021 and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided. The Company has the right to suspend services of one crew and only one crew at any point in time without payment, fee or other obligation associated with the suspended crew, given appropriate notification of suspension. The Company has determined that the agreement with Stingray Pressure is an operating lease due to the implicit identification of assets and the evaluation that the Company has the right to control the identified assets. The operating lease liability associated with this agreement is based on the minimum contractual obligations, which is the monthly service fee for one crew, and does not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.
The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. These agreements are typically structured with non-cancelable terms of one to five years. The Company has determined these agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. The Company has included any renewal options that it has determined are reasonably certain of exercise in the determination of the lease terms.
Discount Rate
As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
Maturities of operating lease liabilities as of September 30, 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Remaining 2019
|
|
$
|
10,190
|
|
|
2020
|
|
31,460
|
|
|
2021
|
|
22,731
|
|
|
2022
|
|
115
|
|
|
2023
|
|
90
|
|
|
Thereafter
|
|
30
|
|
|
Total lease payments
|
|
$
|
64,616
|
|
|
Less: Imputed interest
|
|
(2,247
|
)
|
|
Total
|
|
$
|
62,369
|
|
Lease cost for the three and nine months ended September 30, 2019 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
2019
|
|
2019
|
|
|
(In thousands)
|
|
Operating lease cost
|
$
|
4,551
|
|
|
$
|
20,835
|
|
|
Operating lease cost - related party
|
5,610
|
|
|
16,830
|
|
|
Variable lease cost
|
105
|
|
|
1,065
|
|
|
Variable lease cost - related party
|
5,357
|
|
|
64,968
|
|
|
Short-term lease cost
|
224
|
|
|
407
|
|
|
Total lease cost(1)
|
$
|
15,847
|
|
|
$
|
104,105
|
|
|
|
|
|
|
|
|
|
(1)
|
The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations.
|
Supplemental cash flow information for the nine months ended September 30, 2019 related to leases was as follows:
|
|
|
|
|
|
|
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
(In thousands)
|
|
Operating cash flows from operating leases
|
|
$
|
146
|
|
|
Investing cash flow from operating leases
|
|
$
|
18,998
|
|
|
Investing cash flow from operating leases - related party
|
|
$
|
78,518
|
|
The weighted-average remaining lease term as of September 30, 2019 was 1.82 years. The weighted-average discount rate used to determine the operating lease liability as of September 30, 2019 was 3.66%.
The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.
The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to potential limitations under Internal Revenue Code Section 382 (“Section 382”) and its related tax regulations. The utilization of these attributes may be limited if certain ownership changes by 5% stockholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change of more than 50% in the beneficial ownership of Gulfport. The Company updates its Section 382 analysis to determine if an ownership change has occurred at each reporting period. If it is determined that an ownership change has occurred under these rules, the Company would generally be subject to an annual limitation on the use of pre-ownership change NOL carryforwards and certain other losses and/or credits. In addition, certain future transactions regarding the Company's equity, including the cumulative effects of small transactions as well as transactions beyond the Company’s control, could cause an ownership change and therefore a potential limitation on the annual utilization of its deferred tax assets.
For the three month period ended March 31, 2019, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.
As of June 30, 2019, in part because in the current year the Company achieved more than three years of cumulative pretax income in the U.S. federal tax jurisdiction and the Company determined that an ownership change under Internal Revenue Code Section 382 did not occur that would further limit its ability to utilize net operating loss carryforwards, management determined that there was sufficient positive evidence to conclude that it is more likely than not that additional deferred taxes of $207.4 million are realizable.
For the three and nine months ended September 30, 2019, the Company recognized $28.0 million and $207.4 million as a discrete tax benefit in the respective periods. It therefore reduced the valuation allowance accordingly and maintains a valuation allowance of $4.8 million related to foreign tax credits, general business credits and net operating losses in jurisdictions for which it has determined that it is more likely than not that deferred tax assets would not be realized before expiration.
As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. This assessment relies upon a number of areas of management’s judgment regarding forecast of results in subsequent years. Changes in those judgments could require the Company to establish a valuation allowance for currently recognized deferred tax assets in a subsequent reporting period. In addition, if the Company incurred an Internal Revenue Code Section 382 ownership change it would significantly limit the Company’s ability to utilize net operating loss carryforwards and other tax attributes.
For the three and nine months ended September 30, 2019, the Company's estimated annual effective tax rates were approximately 273.4% and (62.1)%, respectively. The effective tax rate varies from the expected statutory tax rate of 21% primarily because of the release of the valuation allowance of $207.4 million for the nine months ended September 30, 2019. The Company also recognized tax expense of $1.6 million and $1.7 million for the three and nine months ended September 30, 2019, respectively, related to equity compensation book amounts that exceed the tax deduction.