NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Company
Gulfport Energy Corporation is an independent natural gas-weighted exploration and production company focused on the production of natural gas, crude oil and NGL in the United States. The Company's principal properties are located in eastern Ohio targeting the Utica and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. Gulfport filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code on November 13, 2020, and subsequently operated as a debtor-in-possession, in accordance with applicable provisions of the Bankruptcy Code, until its emergence on May 17, 2021. The Company refers to the post-emergence reorganized organization in the condensed financial statements and footnotes as the "Successor" for periods subsequent to May 17, 2021, and the pre-emergence organization as "Predecessor" for periods on or prior to May 17, 2021.
Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On the Petition Date, the Debtors filed voluntary petitions of relief under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ).
The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021. The Debtors emerged from the Chapter 11 Cases on the Emergence Date. The Company's bankruptcy proceedings and related matters have been summarized below.
During the pendency of the Chapter 11 Cases, the Company continued to operate its business in the ordinary course as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted the first day relief requested by the Company that was designed primarily to mitigate the impact of the Chapter 11 Cases on its operations, vendors, suppliers, customers and employees. As a result, the Company was able to conduct normal business activities and satisfy all associated obligations for the period following the Petition Date and was also authorized to pay mineral interest owner royalties, employee wages and benefits, and certain vendors and suppliers in the ordinary course for goods and services provided prior to the Petition Date. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to compromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the Emergence Date.
The Company applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements for the period ended May 17, 2021. ASC 852 specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings were classified as liabilities subject to compromise on the consolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the Chapter 11 Cases are recorded as reorganization items, net. Refer to Note 3 for more information regarding reorganization items. In connection with the Company's emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and applied fresh start accounting on the Emergence Date. See Note 3 for more information regarding the application of fresh start accounting.
Risks and Uncertainties
The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of Gulfport’s control, including changes in market supply and demand. The COVID-19 pandemic and related shut-down of various sectors of the global economy resulted in a significant reduction in global demand for natural gas and crude oil since 2020. Changes in market supply and demand are also impacted by OPEC+ production levels, weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for Gulfport’s production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future natural gas, crude oil and NGL production. See Note 13 for further discussion of the Company's commodity derivative contracts. Principles of Consolidation
The consolidated financial statements include the Company and its wholly-owned subsidiaries, Gulfport Energy Operating Corporation, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC, Puma Resources, Inc., Gulfport Appalachia LLC, Gulfport Midstream Holdings, LLC, Gulfport MidCon, LLC and Mule Sky LLC. All intercompany balances and transactions are eliminated in consolidation.
Segments
The Company's assets and operations consist of one reportable segment. The Company has a single management team that administers all properties as a whole rather than by geographic operating area. Further, the Company measures financial performance as a single enterprise and not on an area-by-area basis.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the consolidated financial statements.
Accounts Receivable
The Company sells oil and natural gas to various purchasers and participates in drilling, completion and operation of oil and natural gas wells with joint interest owners on properties the Company operates. The related receivables are classified as accounts receivable—oil and natural gas sales and accounts receivable—joint interest and other, respectively. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. No material allowance was deemed necessary at December 31, 2022 and December 31, 2021.
Oil and Gas Properties
The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Additionally, interest is capitalized on the cost of unproved oil and natural gas properties that are excluded from amortization for which exploration and development activities are in process or expected within the next 12 to 18 months.
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 proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue (only to the extent that the derivative instruments are treated as cash flow hedges for
accounting purposes), and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of unproved properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash write-down is required. Ceiling test impairment can result in a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. The Company recognized a ceiling test impairment of $117.8 million in the second quarter of 2021.
Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties, are depleted by an equivalent units-of-production method, converting barrels to gas at the ratio of one barrel of oil to six Mcf of gas. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proved oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled approximately $178.5 million and $211.0 million at December 31, 2022 and December 31, 2021, respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development.
The Company accounts for its abandonment and restoration liabilities by recording a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
Other Property and Equipment
Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 15 years.
Foreign Currency
The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company had an equity investment in a Canadian entity whose functional currency is the Canadian dollar. As of the Emergence Date, this investment is no longer accounted for under the equity method of accounting. Under the equity method of accounting, the assets and liabilities of the Canadian investment were translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses were translated at average rates for the periods presented and equity contributions are translated at the current exchange rate in effect at the date of the contribution. In addition, until the Emergence Date, the Company had an equity investment in a U.S. company that has a subsidiary that is a Canadian entity whose functional currency is the Canadian dollar. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity (deficit).
The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive loss, exclusive of taxes (in thousands):
| | | | | |
| |
December 31, 2020 | $ | (41,651) | |
December 31, 2021 | $ | — | |
December 31, 2022 | $ | — | |
Net Income (Loss) per Common Share
Basic net income (loss) per common share is computed by dividing income attributable to Common Stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if options or other contracts to issue Common Stock were exercised or converted into Common Stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income (loss) per common share are illustrated in Note 12. Income Taxes
The amount of income taxes recorded by Gulfport requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
The Company is subject to U.S. federal income tax as well as income tax of multiple state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2019. As of December 31, 2022, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. See Note 11 for further discussion of the Company's income taxes. Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. Sales of natural gas, oil and condensate and NGL 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 a point-in-time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to (i) whether the purchaser can direct the use of the product, (ii) the transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title.
Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression in the accompanying consolidated statements of operations.
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.
The recognition of gains or losses on derivative instruments is outside the scope of ASC 606, Revenue from Contracts with Customers and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.
The Company has elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer, such as sales tax, use tax, value-added tax and similar taxes.
See Note 9 for additional discussion of revenue from contracts with customers.
Accounting for Stock-based Compensation
Share-based payments to employees, including grants of restricted stock units and performance vesting restricted stock units, are recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for restricted shares range between one to four years with annual vesting installments. The Company does not recognize expense based on an estimate of forfeitures, but rather recognizes the impact of forfeitures only as they occur.
Derivative Instruments
The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and NGL production. All derivative instruments are recognized as assets or liabilities in the consolidated balance sheets, measured at fair value. The Company does not apply hedge accounting to derivative instruments. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets, the fair value determination of acquired assets and liabilities and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Reclassification
Certain reclassifications have been made to prior period financial statements and related disclosures to conform to current period presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net income (loss) or total operating cash flows.
Supplemental cash flow and non-cash information (in thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Supplemental disclosure of cash flow information: | | | | | | | | |
Cash paid for reorganization items, net | $ | — | | | $ | 85,706 | | | | $ | 87,199 | | | $ | 24,553 | |
Interest payments | 57,685 | | | 33,295 | | | | 7,272 | | | 84,823 | |
Income tax receipts | — | | | (9,381) | | | | — | | | — | |
Changes in operating assets and liabilities: | | | | | | | | |
(Increase) decrease in accounts receivable - oil, natural gas, and natural gas liquids sales | (45,550) | | | (52,143) | | | | (60,832) | | | 1,331 | |
(Increase) decrease in accounts receivable - joint interest and other | (1,095) | | | (5,178) | | | | (3,005) | | | 36,055 | |
Increase (decrease) in accounts payable and accrued liabilities | 59,879 | | | (72,912) | | | | 79,193 | | | 126,434 | |
(Increase) decrease in prepaid expenses | 4,863 | | | 13,559 | | | | 135,471 | | | (154,948) | |
(Increase) decrease in other assets | 1,330 | | | 3,630 | | | | 3,067 | | | (2,087) | |
Total changes in operating assets and liabilities | $ | 19,427 | | | $ | (113,044) | | | | $ | 153,894 | | | $ | 6,785 | |
Supplemental disclosure of non-cash transactions: | | | | | | | | |
Capitalized stock-based compensation | $ | 2,948 | | | $ | 1,101 | | | | $ | 930 | | | $ | 2,860 | |
Asset retirement obligation capitalized | 2,169 | | | 7,964 | | | | 546 | | | 2,358 | |
Asset retirement obligation removed due to divestiture | (7) | | | — | | | | — | | | (2,213) | |
Interest capitalized | — | | | 198 | | | | — | | | 907 | |
Pre-petition revolver principal transfer to DIP credit facility | — | | | — | | | | — | | | 157,500 | |
Fair value of contingent consideration asset on date of divestiture | — | | | — | | | | — | | | 23,090 | |
Release of Common Stock held in reserve | 28,220 | | | 23,893 | | | | — | | | — | |
Foreign currency translation gain on equity method investments | — | | | — | | | | 2,570 | | | 3,833 | |
Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consisted of the following at December 31, 2022 and December 31, 2021 (in thousands):
| | | | | | | | | | | |
| Successor |
| December 31, 2022 | | December 31, 2021 |
Accounts payable and other accrued liabilities | $ | 117,529 | | | $ | 98,821 | |
Revenue payable and suspense | 222,721 | | | 180,857 | |
Accrued contract rejection damages and shares held in reserve | 40,996 | | | 69,216 | |
Accrued transportation, gathering, processing, and compression | 56,138 | | | 45,117 | |
Total accounts payable and accrued liabilities | $ | 437,384 | | | $ | 394,011 | |
Recent Adopted Accounting Pronouncements
In August 2020, the FASB issued ASU No. 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This new standard simplifies and adds disclosure requirements for the accounting and measurement of convertible instruments. It eliminates the treasury stock method for convertible instruments and requires application of the “if-converted” method for certain agreements. In addition, the standard eliminates the beneficial conversion
and cash conversion accounting models that require separate accounting for embedded conversion features and the recognition of a debt discount and related amortization to interest expense of those embedded features.
The Company elected to early adopt this standard effective on the Emergence Date. The Company adopted the new standard using the modified retrospective approach transition method. No cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The consolidated financial statements for the Successor Period are presented under the new standard, while the Predecessor periods and comparative periods are not adjusted and continue to be reported in accordance with the Company's historical accounting policy.
2.CHAPTER 11 EMERGENCE
As described in Note 1, on November 13, 2020, the Debtors filed the Chapter 11 Cases and the Plan, which was subsequently amended, and entered the confirmation order on April 28, 2021. The Debtors then emerged from bankruptcy upon effectiveness of the Plan on May 17, 2021. Capitalized terms used but not defined herein shall have the meaning ascribed to them in the Plan. Plan of Reorganization
In accordance with the Plan confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company's emergence from bankruptcy on May 17, 2021:
•Shares of the Predecessor's common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company issued 19,845,780 shares of Common Stock and 55,000 shares of Preferred Stock, which were the result of the transactions described below. The Company also entered into a registration rights agreement and amended its articles of incorporation and bylaws for the authorization of the Common Stock and Preferred Stock among other corporate governance actions. See Note 6 and 7 for further discussion of the Company's post-emergence equity; •All outstanding obligations under the Predecessor Senior Notes were cancelled;
•The Predecessor effectuated certain restructuring transactions, including entering into a plan of Merger with Gulfport Merger Sub, Inc., a newly formed, wholly owned subsidiary of Gulfport ("Merger Sub"), pursuant to which Merger Sub was merged with and into Predecessor, resulting in the Predecessor becoming a wholly owned subsidiary of Gulfport;
•The Debtors entered into a Second Amended and Restated Credit Agreement (the "Exit Credit Agreement") with the Bank of Nova Scotia as administrative agent, various lender parties and acknowledged and agreed to by certain of Gulfport's subsidiaries, as guarantors, providing for (i) a new money senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $1.5 billion (the "Exit Facility"); (ii) a senior secured term loan in an aggregate maximum principal amount of up to $180 million (the "First-Out Term Loan") and together with the Exit Facility (the "Exit Credit Facility"), collectively with an initial borrowing base and elected commitment amount of up to $580 million (less the amount of any term loan deemed funded by any RBL Lender that is not a Consenting RBL Lender);
•The Company entered into an indenture to issue up to $550 million aggregate principal amount of its 8.000% senior notes due 2026, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the guarantors party thereto (such indenture, the “1145 Indenture,” and such senior notes issued thereunder, the “1145 Notes”), under section 1145 of the Bankruptcy Code (“Section 1145”). Certain eligible holders have made an election (the “4(a)(2) Election”) entitling such holders to receive senior notes issued pursuant to an indenture, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the guarantors party thereto (such indenture, the “4(a)(2) Indenture,” and such senior notes issued thereunder, the “4(a)(2) Notes”), under Section 4(a)(2) of the Securities Act of 1933, as amended as opposed to its share of the up to $550 million aggregate principal amount of 1145 Notes. The 4(a)(2) Indenture's terms are substantially similar to the terms of the 1145 Indenture. The 1145 Indenture and the 4(a)(2) Indenture are referred to together as the "Indentures". The 1145 Notes and the 4(a)(2) Notes are collectively referred to as the "2026 Senior Notes";
•The DIP Credit Facility indefeasibly converted into the Exit Facility, and all commitments under the DIP Credit Facility terminated. Each holder of an Allowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility;
•Each holder of an Allowed Notes Claim received its pro rata share of 19,714,204 shares of Common Stock, 54,967 shares of Preferred Stock and New Unsecured Senior Notes;
•1,678,755 shares of Common Stock were issued to the Disputed Claims reserve;
•Each holder of a Class 4A Claim greater than the Convenience Claim Threshold received its pro rata share of 119,679 shares of Common Stock (which were issued to the Unsecured Claims Distribution Trust), $10 million in cash, subject to adjustment by the Unsecured Claims Distribution Trustee, and 100% of the Mammoth Shares;
•Each holder of a Class 4B claim greater than the Convenience Claim Threshold received its pro rata share of 11,897 shares of Common Stock, 33 shares of Preferred Stock, the Rights Offering Subscription Rights and the 2026 Senior Notes;
•Each holder of a Convenience Class Claim will share in a $3 million cash distribution pool, which the Unsecured Claims Distribution Trustee may increase by an additional $2 million by reducing the Gulfport Parent Cash Pool;
•Each intercompany claim was cancelled on the Emergence Date and holders of intercompany interests received no recovery or distribution;
•The Company conducted a Rights Offering and issued 50,000 shares of Preferred Stock at $1,000 per share to holders of claims against the Predecessor Subsidiaries, raising $50 million in proceeds. Additionally, 5,000 shares were issued to the Back Stop Commitment counterparties in lieu of cash consideration as per the Backstop Commitment Agreement; and
•The Company adopted the Gulfport Energy Corporation 2021 Stock Incentive Plan (the "Incentive Plan") effective on the Emergence Date and reserved 2,828,123 shares of Common Stock for issuance to Gulfport's employees and non-employee directors pursuant to equity incentive awards to be granted under the Incentive Plan.
Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company's post-emergence Board of Directors is comprised of five directors, including the Company's former Chief Executive Officer and current Executive Chairman, Timothy Cutt, and four non-employee directors, David Wolf, Guillermo Martinez, Jason Martinez and David Reganato.
Executory Contracts
Subject to certain exceptions, under the Bankruptcy Code the Debtors were entitled to assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract was treated as a pre-petition breach of such contract and, subject to certain exceptions, relieved the Debtors from performing future obligations under such contract but entitled the counterparty to a pre-petition general unsecured claim for damages caused by such deemed breach. Alternatively, the assumption of an executory contract or unexpired lease required the Debtors to cure existing monetary defaults under such executory contract or unexpired lease, if any, and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this document, including where applicable quantification of the Company’s obligations under such executory or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights thereto. Refer to Note 19 for more information on potential future rejection damages related to general unsecured claims. 3.FRESH START ACCOUNTING
In connection with the Company's emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and applied fresh start accounting on the Emergence Date. The Company qualified for fresh start accounting because (1) the holders of existing voting shares of the Company prior to the Emergence Date received less than 50% of the voting shares of the Successor's equity following its emergence from bankruptcy and (2) the reorganization value of the Company's assets immediately prior to confirmation of the Plan of approximately $2.3 billion was less than the post-petition liabilities and allowed claims of $3.1 billion.
In accordance with ASC 852, with the application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair value in conformity with FASB ASC Topic 820 - Fair Value Measurements and FASB ASC Topic 805 - Business Combinations. Accordingly, the consolidated financial statements after May 17, 2021 are not comparable with the consolidated financial statements as of or prior to that date. The Emergence Date fair values of the Successor's assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor.
Reorganization Value
Reorganization value is derived from an estimate of enterprise value, or fair value of the Company's interest-bearing debt and stockholders' equity. Under ASC 852, reorganization value generally approximates fair value of the entity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of a restructuring. As set forth in the disclosure statement, amended for updated pricing, and approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $1.3 billion and $1.9 billion. With the assistance of third-party valuation advisors, the Company determined the enterprise value and corresponding implied equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. Deferred income taxes were determined in accordance with FASB ASC Topic 740 - Income Taxes. For GAAP purposes, the Company valued the Successor's individual assets, liabilities and equity instruments and determined an estimate of the enterprise value within the estimated range. Management concluded that the best estimate of enterprise value was $1.6 billion. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process.
The enterprise value and corresponding implied equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh start reporting date of May 17, 2021. As estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties, the resolution of contingencies is beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially.
The following table reconciles the enterprise value to the implied fair value of the Successor's equity as of the Emergence Date (in thousands):
| | | | | |
Enterprise Value | $ | 1,600,000 | |
Plus: Cash and cash equivalents(1) | 1,526 | |
Less: Fair value of debt | (852,751) | |
Successor equity value(2) | $ | 748,775 | |
_____________________
(1) Restricted cash is not included in the above table.
(2) Inclusive of $55 million of mezzanine equity.
The following table reconciles the enterprise value to the reorganization value as of the Emergence Date (in thousands):
| | | | | |
Enterprise Value | $ | 1,600,000 | |
Plus: Cash and cash equivalents(1) | 1,526 | |
Plus: Current and other liabilities | 686,489 | |
Plus: Asset retirement obligations | 19,084 | |
Less: Common stock held in reserve for settlement of claims post Emergence Date | (54,109) | |
Reorganization value of Successor assets | $ | 2,252,990 | |
_____________________
(1) Restricted cash is not included in the above table.
The fair values of our oil and natural gas properties, other property and equipment, derivative instruments, equity investments and asset retirement obligations were estimated as of the Emergence Date.
Oil and natural gas properties. The Company's principal assets are its oil and natural gas properties, which are accounted for under the full cost method of accounting. The Company determined the fair value of its oil and natural gas properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future
commodity prices escalated by an inflationary rate after seven years, adjusted for differentials and (v) a market-based weighted average cost of capital by operating area. The Company utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount rates utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area.
Other property and equipment. The fair value of other property and equipment, such as land, buildings, vehicles, computer equipment and other equipment, was maintained at net book value as the carrying value reasonably approximated the fair value of the assets.
Asset retirement obligations. In accordance with FASB ASC Topic 410 - Asset Retirement and Environmental Obligations, the asset retirement obligations associated with the Company's oil and gas assets was valued using the income approach. The fair value of the Company’s asset retirement obligations was revalued based upon estimated current reclamation costs for our assets with reclamation obligations, updated estimates of timing of reclamation obligations, an appropriate long-term inflation adjustment, and the Company's revised credit adjusted risk-free rate. The credit adjusted risk-free rate was based on an evaluation of an interest rate that equates to a risk-free interest rate adjusted for the effect of the Company's credit standing.
Derivative Instruments. The fair value of derivative instruments was adjusted based on the change in the Company’s credit rating reflecting the Company’s credit standing at the Emergence Date.
Equity Investments. The fair value of the Company's investment in Grizzly was reduced by $27 million. The reduction in valuation was based upon the assessment of the investment by the Company's new management and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls which will lead to further dilution of its equity ownership interest.
Consolidated Balance Sheet
The following consolidated balance sheet is as of May 17, 2021. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Emergence Date. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets and liabilities.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of May 17, 2021 |
| | Predecessor | | Reorganization Adjustments | | Fresh Start Adjustments | | Successor |
| | (In thousands) |
Assets | | | | | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 146,545 | | | $ | (145,019) | | (a) | $ | — | | | $ | 1,526 | |
Restricted cash | | — | | 57,891 | (b) | — | | 57,891 |
Accounts receivable—oil and natural gas sales | | 180,711 | | — | | — | | 180,711 |
Accounts receivable—joint interest and other | | 15,431 | | — | | — | | 15,431 |
Prepaid expenses and other current assets | | 86,189 | | (60,894) | (c) | — | | 25,295 |
Short-term derivative instruments | | 3,324 | | — | | 141 | (r) | 3,465 |
Total current assets | | 432,200 | | (148,022) | | 141 | | 284,319 |
Property and equipment: | | | | | | | | |
Oil and natural gas properties, full-cost method | | | | | | | | |
Proved oil and natural gas properties | | 9,558,121 | | — | | (7,860,713) | (s) | 1,697,408 |
Unproved properties | | 1,375,681 | | — | | (1,145,507) | (s) | 230,174 |
Other property and equipment | | 38,026 | | — | | (31,133) | (t) | 6,893 |
Total property and equipment | | 10,971,828 | | — | | (9,037,353) | | 1,934,475 |
Accumulated depletion, depreciation and amortization | | (8,870,723) | | — | | 8,870,723 | (u) | — |
Total property and equipment, net | | 2,101,105 | | — | | (166,630) | | 1,934,475 |
Other assets: | | | | | | | | |
Equity investments | | 27,044 | | — | | (27,044) | (v) | — |
Long-term derivative instruments | | 7,468 | | — | | 715 | (w) | 8,183 |
| | | | | | | | |
Operating lease assets | | 47 | | — | | — | | 47 |
Other assets | | 18,866 | | 7,100 | (d) | — | | 25,966 |
Total other assets | | 53,425 | | 7,100 | | (26,329) | | 34,196 |
Total assets | | $ | 2,586,730 | | | $ | (140,922) | | | $ | (192,818) | | | $ | 2,252,990 | |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | Predecessor | | Reorganization Adjustments | | Fresh Start Adjustments | | Successor |
| | (In thousands) |
Liabilities and Stockholders’ Equity (Deficit) | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable and accrued liabilities | | $ | 384,200 | | | $ | 122,599 | | (e) | $ | — | | | $ | 506,799 | |
| | | | | | | | |
Short-term derivative instruments | | 96,116 | | | — | | | 2,784 | | (x) | 98,900 | |
Current portion of operating lease liabilities | | — | | | 38 | | (f) | — | | | 38 | |
Current maturities of long-term debt | | 280,251 | | | (220,251) | | (g) | — | | | 60,000 | |
Total current liabilities | | 760,567 | | | (97,614) | | | 2,784 | | | 665,737 | |
Non-current liabilities: | | | | | | | | |
Long-term derivative instruments | | 69,331 | | | — | | | 11,411 | | (y) | 80,742 | |
Asset retirement obligation | | — | | | 65,341 | | (h) | (46,257) | | (z) | 19,084 | |
Non-current operating lease liabilities | | — | | | 9 | | (i) | — | | | 9 | |
Long-term debt, net of current maturities | | — | | | 792,751 | | (j) | — | | | 792,751 | |
Total non-current liabilities | | 69,331 | | | 858,101 | | | (34,846) | | | 892,586 | |
Liabilities subject to compromise | | 2,224,449 | | | (2,224,449) | | (k) | — | | | — | |
Total liabilities | | $ | 3,054,347 | | | $ | (1,463,962) | | | $ | (32,062) | | | $ | 1,558,323 | |
Commitments and contingencies | | | | | | | | |
Mezzanine Equity: | | | | | | | | |
Preferred Stock | | $ | — | | | $ | 55,000 | | (l) | $ | — | | | $ | 55,000 | |
Stockholders’ equity (deficit): | | | | | | | | |
Predecessor common stock | | 1,609 | | | (1,609) | | (m) | — | | | — | |
Common Stock | | — | | | 2 | | (n) | — | | | 2 | |
Additional paid-in capital | | 4,215,838 | | | (3,522,064) | | (o) | — | | | 693,774 | |
Common Stock held in reserve | | — | | | (54,109) | | (p) | — | | | (54,109) | |
Accumulated other comprehensive loss | | (40,430) | | | 40,430 | | (q) | — | | | — | |
Retained earnings (accumulated deficit) | | (4,644,634) | | | 4,805,390 | | (q) | (160,756) | | (aa) | — | |
Total stockholders’ equity (deficit) | | $ | (467,617) | | | $ | 1,268,040 | | | $ | (160,756) | | | $ | 639,667 | |
Total liabilities, mezzanine equity and stockholders’ equity (deficit) | | $ | 2,586,730 | | | $ | (140,922) | | | $ | (192,818) | | | $ | 2,252,990 | |
Reorganization Adjustments (in thousands)
(a)The table below reflects changes in cash and cash equivalents on the Emergence Date from implementation of the Plan:
| | | | | | | | |
Release of escrow funds by counterparties as a result of the Plan | | $ | 63,068 | |
Preferred Stock rights offering proceeds | | 50,000 | |
Funds required to rollover the DIP Credit Facility and Pre-Petition Revolving Credit Facility into the Exit Facility | | (175,000) | |
Payment of accrued Pre-Petition Revolving Credit Facility and DIP Credit Facility interest | | (1,022) | |
Payment of issuance costs related to the Exit Credit Facility | | (10,250) | |
Funding of the Professional Fee Escrow | | (43,891) | |
Payment of professional fees at Emergence Date | | (7,964) | |
Transfer to restricted cash for the Unsecured Claims Distribution Trust | | (1,000) | |
Transfer to restricted cash for the Convenience Claims Cash Pool | | (3,000) | |
Transfer to restricted cash for the Parent Cash Pool | | (10,000) | |
Payment of severance costs at Emergence Date | | (5,960) | |
Net change in cash and cash equivalents | | $ | (145,019) | |
(b)Changes in restricted cash reflect the net effect of transfers from cash and cash equivalents for the Professional Fee Escrow and various claims class cash pools.
(c)Changes in prepaid expenses and other current assets include the following:
| | | | | | | | |
Release of escrow funds as a result of the Plan | | $ | (63,068) | |
Recognition of counterparty credits due to settlements effectuated at Emergence | | 4,247 | |
Prepaid compensation earned at Emergence | | (2,073) | |
Net change in prepaid expenses and other current assets | | $ | (60,894) | |
(d)Changes in other assets were due to capitalization of debt issuance costs related to the Exit Credit Facility.
(e)Changes in accounts payable and accrued liabilities included the following:
| | | | | | | | |
Payment of accrued Pre-Petition Revolving Credit Facility and DIP Credit Facility interest | | $ | (1,022) | |
Payment of professional fees at emergence | | (7,964) | |
Accrued payable for claims to be settled via Unsecured Claims Distribution Trust | | 1,000 | |
Accrued payable for claims to be settled via Convenience Claims Cash Pool | | 3,000 | |
Accrued payable for claims to be settled via Parent Cash Pool | | 10,000 | |
Professional fees payable at Emergence | | 18,047 | |
Accrued payable for General Unsecured Claims against Gulfport Parent to be settled via 4A Claims distribution from common shares held in reserve | | 23,894 | |
Accrued payable for General Unsecured Claims against Gulfport Subsidiary to be settled via 4B Claims distribution from common shares held in reserve | | 30,216 | |
Reinstatement of payables due to Plan effects | | 45,428 | |
Net change in accounts payable and accrued liabilities | | $ | 122,599 | |
(f)Changes to current operating lease liabilities reflect the reinstatement of lease liabilities due to contract assumptions.
(g)Changes in the current maturities of long-term debt include the following:
| | | | | | | | |
Current portion of Term Notes issued under the Exit Facility | | $ | 60,000 | |
Payment of DIP Facility to effectuate Exit Facility | | (157,500) | |
Transfer of post-petition RBL borrowings to Exit Facility | | (122,751) | |
Net changes to current maturities of long-term debt | | $ | (220,251) | |
(h)Reflects the reclassification of asset retirement obligations from liabilities subject to compromise.
(i)Changes to non-current operating lease liabilities reflect the reinstatement of lease liabilities due to contract assumptions.
(j)Changes in long-term debt include the following:
| | | | | | | | |
Emergence Date draw on Exit Facility | | $ | 122,751 | |
Noncurrent portion of First-Out Term Loan issued under the Exit Credit Facility | | 120,000 | |
Issuance of 2026 Senior Notes | | 550,000 | |
Net impact to long-term debt, net of current maturities | | $ | 792,751 | |
(k)On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows:
| | | | | | | | |
General Unsecured Claims settled via Class 4A, 4B, and 5B distributions | | $ | 74,098 | |
Predecessor Senior Notes and associated interest | | 1,842,035 | |
Pre-Petition Revolving Credit Facility | | 197,500 | |
Reinstatement of Predecessor Claims as Successor liabilities | | 45,475 | |
Reinstatement of Predecessor asset retirement obligations | | 65,341 | |
Total liabilities subject to compromise settled in accordance with the Plan | | $ | 2,224,449 | |
The resulting gain on liabilities subject to compromise was determined as follows:
| | | | | | | | |
Pre-petition General Unsecured Claims Settled at Emergence | | $ | 74,098 | |
Predecessor Senior Notes Claims settled at Emergence | | 1,842,035 | |
Pre-Petition Revolving Credit Facility | | 197,500 | |
Rollover of Pre-Petition Revolving Credit Facility into Exit RBL Facility | | (197,500) | |
Accrued payable for claims to be settled via Unsecured Claims Distribution Trust | | (1,000) | |
Accrued payable for claims to be settled via Convenience Claims Cash Pool | | (3,000) | |
Accrued payable for claims to be settled via Parent Cash Pool | | (10,000) | |
Accrued payable for shares to be transferred to trust | | (54,109) | |
Issuance of Common Stock to settle Predecessor liabilities | | (639,666) | |
Issuance of 2026 Senior Notes in settlement of Class 4B and 5B claims | | (550,000) | |
Gain on settlement of liabilities subject to compromise | | $ | 658,358 | |
(l)Changes to Preferred Stock reflect the fair value of preferred shares issued in the Rights Offering.
(m)Changes in Predecessor common stock reflect the extinguishment of Predecessor equity as per the Plan.
(n)Changes in Common Stock included the following:
| | | | | | | | |
Issuance of Common Stock to settle General Unsecured Claims against Gulfport Parent (par value) | | $ | — | |
Issuance of Common Stock to settle General Unsecured Claims against Gulfport Subsidiaries (par value) | | 2 | |
Common stock reserved for settlement of claims post Emergence Date (par value) | | — | |
Net change to Common Stock | | $ | 2 | |
(o)Changes to paid in capital included the following:
| | | | | | | | |
Issuance of Common Stock to settle General Unsecured Claims against Gulfport Parent | | $ | 27,751 | |
Issuance of Common Stock to settle General Unsecured Claims against Gulfport Subsidiaries | | 666,022 | |
Extinguishment of Predecessor stock-based compensation | | 4,419 | |
Extinguishment of Predecessor paid in capital | | (4,220,256) | |
Net change to paid in capital | | $ | (3,522,064) | |
(p)Common Stock held in reserve to settle Allowed General Unsecured Claims include:
| | | | | | | | |
Shares held in reserve to settle Allowed Claims against Gulfport Parent | | (23,894) | |
Shares held in reserve to settle Allowed Claims against Gulfport Subsidiary | | (30,215) | |
Total Common Stock held in reserve | | (54,109) | |
(q)Change to retained earnings (accumulated deficit) included the following:
| | | | | | | | |
Gain on settlement of liabilities subject to compromise | | $ | 658,358 | |
Extinguishment of Predecessor common stock and paid in capital | | 4,221,864 | |
Recognition of counterparty credits due to settlements effectuated at Emergence | | 4,247 | |
Deferred compensation earned at Emergence | | (2,073) | |
Extinguishment of Predecessor accumulated other comprehensive income | | (40,430) | |
Write-off of debt issuance costs related to First-Out Term Loan | | (3,150) | |
Severance costs incurred as a result of the Plan | | (5,961) | |
Professional fees earned at Emergence | | (18,047) | |
Rights offering backstop commitment fee | | (5,000) | |
Extinguishment of Predecessor stock-based compensation | | (4,418) | |
Net change to retained earnings (accumulated deficit) | | $ | 4,805,390 | |
Fresh Start Adjustments
(r)The change in fair value of short-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(s)The change in oil and natural gas properties represents the fair value adjustment to the Company's properties due to the adoption of fresh start accounting.
(t)Predecessor accumulated depreciation and amortization for other property and equipment was net against the gross value of the assets with the adoption of fresh start accounting.
(u)Predecessor accumulated depreciation and amortization was eliminated with the adoption of fresh start accounting.
(v)The change in equity investments is due to the fair value adjustment to the Company's Grizzly investment.
(w)The change in fair value of long-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(x)The change in fair value of liabilities related to short-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(y)The change in fair value of liabilities related to long-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(z)The fair value of asset retirement obligations was reduced due to the change in the Company's credit adjusted risk-free rate and expected economic life estimates.
(aa)Changes to retained earnings represent the total impact of fresh start adjustments to the post-reorganization balance sheet.
Reorganization Items, net
The Company has incurred significant expenses, gains and losses associated with the reorganization, primarily the gain on settlement of liabilities subject to compromise, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The accrual for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as stipulated in the Plan. While the claims reconciliation process is ongoing, the estimate of liabilities related to the rejection of certain midstream contracts reflects the best estimate of the most probable outcomes of ongoing litigation and settlement negotiations. The amount of these items, which were incurred in reorganization items, net within the accompanying condensed consolidated statements of operations, have significantly affected the Company's statements of operations.
The following table summarizes the components in reorganization items, net included in the Company's consolidated statements of operations (in thousands):
| | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | | | Period from January 1, 2021 through May 17, 2021 |
Legal and professional advisory fees | $ | — | | | $ | — | | | | | | $ | 81,565 | |
Net gain on liabilities subject to compromise | — | | | — | | | | | | (575,182) | |
Fresh start adjustments, net | — | | | — | | | | | | 160,756 | |
Elimination of Predecessor accumulated other comprehensive income | — | | | — | | | | | | 40,430 | |
Debt issuance costs | — | | | — | | | | | | 3,150 | |
Other items, net | — | | | — | | | | | | 22,383 | |
Total reorganization items, net | $ | — | | | $ | — | | | | | | $ | (266,898) | |
4.PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated DD&A and impairment as of December 31, 2022 and 2021 are as follows (in thousands):
| | | | | | | | | | | |
| Successor |
| December 31, 2022 | | December 31, 2021 |
Proved oil and natural gas properties | $ | 2,418,666 | | | $ | 1,917,833 | |
Unproved properties | 178,472 | | | 211,007 | |
Other depreciable property and equipment | 5,977 | | | 4,943 | |
Land | 386 | | | 386 | |
Total property and equipment | 2,603,501 | | | 2,134,169 | |
Accumulated DD&A and impairment | (545,771) | | | (278,341) | |
Property and equipment, net | $ | 2,057,730 | | | $ | 1,855,828 | |
Oil and Natural Gas Properties
Under the full cost method of accounting, capitalized costs of oil and natural gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1. At December 31, 2022, the net book value of the Company's oil and gas properties was below the calculated ceiling for the period leading up to December 31, 2022. As a result, the Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2022. During the Prior Successor Period and the year ended December 31, 2020, the Company incurred $117.8 million and $1.4 billion of impairments, respectively, as a result of its oil and natural gas properties exceeding its calculated ceiling. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for natural gas, oil and NGL, which significantly reduced proved reserves values and proved reserves. The Company did not record an impairment of its oil and natural gas properties during the Prior Predecessor Period. 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 the 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 $20.2 million, $11.9 million, $8.0 million and $25.0 million for the year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and the year ended December 31, 2020, 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 $0.74, $0.69, $0.45 and $0.61 per Mcfe for the year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and the year ended December 31, 2020, respectively.
The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2022 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Costs Incurred in |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Fresh Start Adjustments (May 17, 2021)(1) | | Total |
Acquisition costs | $ | 17,288 | | | $ | 8,687 | | | | $ | 152,456 | | | $ | 178,431 | |
Exploration costs | — | | | — | | | | — | | | — | |
Development costs | 16 | | | 25 | | | | — | | | 41 | |
Capitalized interest | — | | | — | | | | — | | | — | |
Total oil and natural gas properties not subject to amortization | $ | 17,304 | | | $ | 8,712 | | | | $ | 152,456 | | | $ | 178,472 | |
_____________________
(1) Reflects carrying values of our unproved properties as a result of the application of fresh start accounting upon emergence from bankruptcy (see Note 3 for additional information) that remain in unproved properties as of December 31, 2022.
The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2022 and December 31, 2021 (in thousands):
| | | | | | | | | | | |
| Successor |
| December 31, 2022 | | December 31, 2021 |
Utica | $ | 147,370 | | | $ | 175,028 | |
SCOOP | 31,102 | | | 35,975 | |
Other | — | | | 4 | |
| $ | 178,472 | | | $ | 211,007 | |
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 have five-year extension terms, which could extend this time frame beyond five years.
Asset Retirement Obligation
A reconciliation of the Company's asset retirement obligation for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period is as follows (in thousands):
| | | | | |
Asset retirement obligation at January 1, 2021 (Predecessor) | $ | 63,566 | |
Liabilities incurred | 546 | |
Accretion expense | 1,229 | |
Ending balance as of May 17, 2021 (Predecessor) | $ | 65,341 | |
Fresh start adjustments(1) | (46,257) | |
| |
| |
Asset retirement obligation at May 18, 2021 (Successor) | $ | 19,084 | |
Liabilities incurred | 204 | |
Accretion expense | 1,214 | |
Revisions in estimated cash flows(2) | 7,762 | |
Asset retirement obligation at December 31, 2021 (Successor) | $ | 28,264 | |
Liabilities incurred | 96 | |
Liabilities removed due to divestitures | (7) | |
Accretion expense | 2,746 | |
Revisions in estimated cash flows(2) | 2,072 | |
Asset retirement obligation at December 31, 2022 (Successor) | $ | 33,171 | |
_____________________(1) As discussed in Note 3, the Company recorded its asset retirement obligation at fair value as of the Emergence Date. (2) Revisions represent changes in the present value of liabilities resulting from changes in estimated costs.
5.LONG-TERM DEBT
Long-term debt consisted of the following items as of December 31, 2022 and 2021 (in thousands):
| | | | | | | | | | | |
| Successor |
| December 31, 2022 | | December 31, 2021 |
Credit Facility | $ | 145,000 | | | $ | 164,000 | |
8.000% senior unsecured notes due 2026 | 550,000 | | | 550,000 | |
Net unamortized debt issuance costs | (845) | | | (1,054) | |
Total Debt, net | 694,155 | | | 712,946 | |
Less: current maturities of long term debt | — | | | — | |
Total Debt reflected as long term | $ | 694,155 | | | $ | 712,946 | |
Credit Facility
On October 14, 2021, the Company entered into the Existing Credit Facility with JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties. The Existing Credit Facility provided for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850 million and an initial aggregate elected commitment amount of $700 million. The Existing Credit Facility also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Credit Facility matures October 14, 2025.
The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year.
On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement ("Amendment"), which amended the Existing Credit Facility (as amended, the "Credit Facility"). The Amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion with the elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations, (c) amended the covenants governing restricted payments to (i) increased the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permitted additional restricted payments to redeem preferred equity until December 31, 2022, provided certain leverage, no event of default or borrowing base deficiency and availability tests were met, and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.
On October 31, 2022, the Company completed its semi-annual borrowing base redetermination during which the borrowing base under the Credit Facility was reconfirmed at $1.0 billion with the elected commitments remaining at $700 million.
The Credit Facility bears interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization. The Company is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company is also required to pay customary letter of credit and fronting fees.
The Credit Facility requires the Company to maintain as of the last day of each fiscal quarter (i) a net funded leverage ratio of less than or equal to 3.25 to 1.00, and (ii) a current ratio of greater than or equal to 1.00 to 1.00.
The obligations under the Credit Facility, certain swap obligations and certain cash management obligations, are guaranteed by the Company and the wholly-owned domestic material subsidiaries of the Borrower (collectively, the “Guarantors” and, together with the Borrower, the “Loan Parties”) and secured by substantially all of the Loan Parties’ assets (subject to customary exceptions).
The Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to a number of limitations and exceptions.
As of December 31, 2022, the Company had $145.0 million outstanding borrowings under the Credit Facility, $113.4 million in letters of credit outstanding and was in compliance with all covenants under the credit agreement.
As of December 31, 2022, the Credit Facility bore interest at a weighted average rate of 7.39%.
2026 Senior Notes
As discussed in Note 2, on the Emergence Date, pursuant to the terms of the Plan, the Company issued $550 million aggregate principal amount of its 8.000% senior notes due 2026. The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2026 Senior Notes is payable semi-annually, on June 1 and December 1 of each year. The 2026 Senior Notes were issued under the Indentures, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the Guarantors and mature on May 17, 2026. The covenants of the 1145 Indenture (other than the payment covenant) require that the Company comply with the covenants of the 4(a)(2) Indenture, as amended. The 4(a)(2) Indenture contains covenants limiting the Issuer’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) pay dividends or distributions in respect of certain equity interests or redeem, repurchase or retire certain equity interests or subordinated indebtedness, (iii) make certain investments, (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in certain lines of business, (viii) engage in consolidations, mergers and acquisitions, (ix) create unrestricted subsidiaries and (x) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the 2026 Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply.
Exit Credit Facility
As discussed in Note 2, on the Emergence Date, pursuant to the terms of the Plan, the Company entered into the Exit Credit Agreement, which provided for (i) the Exit Facility in an aggregate principal amount of up to $1.5 billion and (ii) the First-Out Term Loan in an aggregate maximum amount of up to $180.0 million. The Exit Facility had an initial borrowing base and elected commitment amount of up to $580.0 million. Loans drawn under the Exit Facility were not subject to amortization, while loans drawn under the First-Out Term Loan amortized with $15.0 million quarterly installments, commencing on the closing date and occurring every three months after the closing date. The Exit Credit Facility was scheduled to mature on May 17, 2024.
The Exit Facility provided for a $150.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Exit Facility also included a $40 million availability blocker that was to remain in place until Successful Midstream Resolution (as defined in the Exit Credit Agreement). The Credit Facility amended and refinanced the Exit Credit Facility.
Chapter 11 Proceedings - Predecessor Debt
Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our secured and unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, Section 362 of the Bankruptcy Code stayed the creditors from taking any action as a result of the default.
The principal amounts from the Predecessor Senior Notes, Building Loan and Pre-Petition Revolving Credit Facility, other than letters of credit drawn on the Pre-Petition Revolving Credit Facility after the Petition Date, were classified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.
Debtor-in-Possession Credit Agreement
Pursuant to the RSA, the Consenting RBL Lenders agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of (a) $105 million of new money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The terms and conditions of the DIP Credit Facility are set forth in that certain form of credit agreement governing the DIP Credit Facility. The proceeds of the DIP Credit Facility were used for, among other things, post-
petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations. On the Emergence Date, the DIP Facility was terminated and the lenders indefeasibly converted into the Exit Facility. Each holder of an allowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility.
Pre-Petition Revolving Credit Facility
Prior to the Emergence Date, the Company had entered into a senior secured revolving credit facility agreement, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The Pre-Petition Revolving Credit Facility had a borrowing base of $580 million. On the Emergence Date, the Pre-Petition Revolving Credit Facility was terminated and the lenders indefeasibly converted into the Exit Credit Facility. Each holder of an allowed claim under the Pre-Petition Revolving Credit Facility received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility.
Predecessor Senior Notes
On the Emergence Date, all outstanding obligations under the Predecessor Senior Notes were cancelled in accordance with the Plan and each holder of an allowed unsecured notes claim received their pro-rata share of 19.7 million shares of Common Stock and $550 million of the 2026 Senior Notes.
Predecessor Building Loan
In June 2015, the Company entered into a loan for the construction of the Company's corporate headquarters in Oklahoma City, which was substantially completed in December 2016. On the Emergence Date, ownership of the Company's corporate headquarters reverted to the Building Loan lender and the Company entered into a short-term lease agreement for the headquarters with the lender. As a result, the Building Loan liability was discharged as of the Emergence Date.
Predecessor Debt Repurchases
In July of 2019, the Company's Board of Directors authorized $100 million of cash to be used to repurchase its Senior Notes in the open market at discounted values to par. In December 2019, the Company's Board of Directors increased the authorized size of its senior note repurchase program to $200 million in total. During the year ended December 31, 2020, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $73.3 million aggregate principal amount of its outstanding Predecessor Senior Notes for $22.8 million in cash and recognized a $49.6 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.
Interest Expense
The following schedule shows the components of interest expense for the year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and the year ended December 31, 2020 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Cash paid for interest | $ | 57,685 | | | $ | 33,295 | | | | $ | 7,272 | | | $ | 84,823 | |
Change in accrued interest | (826) | | | 6,061 | | | | (1,503) | | | 30,600 | |
Capitalized interest | — | | | (198) | | | | — | | | (907) | |
Amortization of loan costs | 2,914 | | | 1,663 | | | | — | | | 5,563 | |
Other | — | | | 32 | | | | (1,610) | | | — | |
Total interest expense | $ | 59,773 | | | $ | 40,853 | | | | $ | 4,159 | | | $ | 120,079 | |
The Company did not capitalize interest expense for the year ended December 31, 2022 or Prior Predecessor Period. The Company capitalized approximately $0.2 million and $0.9 million in interest expense to undeveloped oil and natural gas properties during the Prior Successor Period and the year ended December 31, 2020, respectively.
Fair Value of Debt
At December 31, 2022, the carrying value of the outstanding debt represented by the 2026 Senior Notes was approximately $549.2 million. Based on the quoted market prices (Level 1), the fair value of the 2026 Senior Notes was determined to be approximately $542.7 million at December 31, 2022.
6.MEZZANINE EQUITY
As discussed in Note 2, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State on the Emergence Date to provide for, among other things, (i) the authority to issue 42 million shares of Common Stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of Preferred Stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share. Mezzanine Equity
Preferred Stock
On the Emergence Date, the Successor issued 55,000 shares of Preferred Stock.
Holders of Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference (with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of Preferred Stock (“PIK Dividends”). Gulfport currently has the option to pay either cash or PIK dividends on a quarterly basis.
Each holder of shares of Preferred Stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the shares of Preferred Stock that it holds into a number of shares of Common Stock equal to the quotient obtained by dividing (x) the product obtained by multiplying (i) the Liquidation Preference times (ii) an amount equal to one (1) plus the Per Share Makewhole Amount (as defined in the Preferred Terms) on the date of conversion, by (y) $14.00 per share (as may be adjusted under the Preferred Terms) (the “Conversion Price”). The shares of Preferred Stock outstanding at December 31, 2022 would convert to 3.7 million shares of Common Stock if all holders of Preferred Stock exercised their Conversion Right.
Gulfport shall have the right, but not the obligation, to redeem all, but not less than all, of the outstanding shares of Preferred Stock by notice to the holders of Preferred Stock, at the greater of (i) the aggregate value of the Preferred Stock, calculated by the Current Market Price (as defined in the Preferred Terms) of the number of shares of Common Stock into which, subject to redemption, such Preferred Stock would have been converted if such shares were converted pursuant to the Conversion Right at the time of such redemption and (ii) (y) if the date of such redemption is on or prior to the three year anniversary of the Emergence Date, the sum of the Liquidation Preference plus the sum of all unpaid PIK Dividends through the three year anniversary of the Emergence Date, or (x) if the date of such redemption is after the three year anniversary of the Emergence Date, the Liquidation Preference (the “Redemption Price”).
Following the Emergence Date, if there is a Fundamental Change (as defined in the Preferred Terms), Gulfport is required to redeem all, but not less than all, of the outstanding shares of Preferred Stock by cash payment of the Redemption Price per share of Preferred Stock within three (3) business days of the occurrence of such Fundamental Change. Notwithstanding the foregoing, in the event of a redemption pursuant to the preceding sentence, if Gulfport lacks sufficient cash to redeem all outstanding shares of Preferred Stock, the Company is required to redeem a pro rata portion of each holder’s shares of Preferred Stock.
The Preferred Stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into Common Stock.
The Preferred Stock has been classified as mezzanine equity in the accompanying consolidated balance sheets due to the redemption features noted above.
Dividends and Conversions
During the year ended December 31, 2022, the Company paid $5.4 million of cash dividends to holders of our Preferred Stock. During the Prior Successor Period, the Company paid dividends on our Preferred Stock, which included 3,071 shares of Preferred Stock paid in kind, approximately $55 thousand of cash-in-lieu of fractional shares, and $1.5 million of cash dividends to holders of our Preferred Stock.
The following table summarizes activity of the Company’s Preferred Stock for the year ended December 31, 2022 and Prior Successor Period:
| | | | | | | | |
Preferred Stock at May 18, 2021 (Successor) | | 55,000 | |
Issuance of Preferred Stock | | 3,071 | |
Conversion of Preferred Stock | | (175) | |
Preferred Stock at December 31, 2021 (Successor) | | 57,896 | |
Conversion of Preferred Stock | | (5,601) | |
Preferred Stock at December 31, 2022 (Successor) | | 52,295 | |
7.EQUITY
As discussed in Note 2, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State on the Emergence Date to provide for, among other things, (i) the authority to issue 42 million shares of Common Stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of Preferred Stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share. Common Stock
On the Emergence Date, all existing shares of the Predecessor's common stock were cancelled. The Successor issued approximately 19.8 million shares of Common Stock and 1.7 million shares of Common Stock were issued to the Disputed Claims reserve.
In January 2022 approximately 876,000 shares in the Disputed Claims reserve at December 31, 2021 were issued to certain claimants. As of December 31, 2022, approximately 62,000 shares continue to be held in the Disputed Claims reserve and may be issued upon finalization of remaining claims.
Stock Repurchase Program
In November 2021 the Company's Board of Directors approved a stock repurchase program to acquire up to $100 million of its Common Stock and increased the authorization from $100 million to $200 million in April 2022 and from $200 million to $300 million in July 2022 ("Repurchase Program"). Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of Common Stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through June 30, 2023, and may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time. The following table summarizes activity under the Repurchase Program for the year ended December 31, 2022 (number of shares and dollar value of shares purchased shown in thousands):
| | | | | | | | | | | | | | | | | | | | |
| | Total Number of Shares Purchased | | Dollar Value of Shares Purchased | | Average Price Paid Per Share |
First quarter 2022 | | 438 | | | $ | 35,512 | | | $ | 81.06 | |
Second quarter 2022 | | 1,416 | | | 127,510 | | | 90.06 | |
Third quarter 2022 | | 753 | | | 64,549 | | | 85.72 | |
Fourth quarter 2022 | | 293 | | | 23,197 | | | 79.19 | |
Total | | 2,900 | | | $ | 250,768 | | | $ | 86.47 | |
8.STOCK-BASED COMPENSATION
As discussed in Note 2, on the Emergence Date, the Company's Predecessor common stock was cancelled and the Company's Successor Common Stock was issued. Accordingly, the Company's then existing stock-based compensation awards were also cancelled, which resulted in the recognition of previously unamortized expense of $4.4 million related to the cancelled awards on the date of cancellation. The expense was included in reorganization items, net on the accompanying consolidated statements of operations. As a result, stock-based compensation for the Predecessor and Successor periods are not comparable. Successor Stock-Based Compensation
As of the Emergence Date, the Board of Directors adopted the Incentive Plan with a share reserve equal to 2.8 million shares of Common Stock. The Incentive Plan provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and performance awards or any combination of the foregoing. The Company has granted both restricted stock units and performance vesting restricted stock units to employees and directors pursuant to the Incentive Plan, as discussed below. During the year ended December 31, 2022 and Prior Successor Period, the Company's stock-based compensation expense was $8.7 million and $3.1 million, respectively, of which the Company capitalized $2.9 million and $1.1 million, respectively, relating to its exploration and development efforts. Stock compensation expense, net of the amounts capitalized, is included in general and administrative expenses in the accompanying consolidated statements of operations. As of December 31, 2022, the Company has awarded an aggregate of approximately 265 thousand restricted stock units and approximately 191 thousand performance vesting restricted stock units, net of forfeited awards, under the Incentive Plan.
The following table summarizes restricted stock unit activity for the Prior Successor Period and year ended December 31, 2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 May 18, 2021 | — | | | $ | — | | | — | | | $ | — | |
Granted | 200,484 | | | 66.05 | | | 153,138 | | | 48.54 | |
Vested | — | | | — | | | — | | | — | |
Forfeited/canceled | (2,071) | | | 66.89 | | | — | | | — | |
Unvested shares as of December 31, 2021 | 198,413 | | | $ | 66.04 | | | 153,138 | | | $ | 48.54 | |
Granted | 78,192 | | | $ | 96.90 | | | 37,666 | | | $ | 66.82 | |
Vested | (67,564) | | | 65.91 | | | — | | | — | |
Forfeited/canceled | (11,269) | | | 80.11 | | | — | | | — | |
Unvested shares as of December 31, 2022 | 197,772 | | | $ | 77.49 | | | 190,804 | | | $ | 52.15 | |
Successor Restricted Stock Units
Restricted stock units awarded under the Incentive Plan generally vest over a period of 3 to 4 years in the case of employees and 4 years in the case of directors upon the recipient meeting applicable service requirements. Stock-based compensation expense is 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 the grant. Unrecognized compensation expense as of December 31, 2022, was $12.3 million. The expense is expected to be recognized over a weighted average period of 2.13 years.
Successor Performance Vesting Restricted Stock Units
The Company has awarded performance vesting restricted stock units to certain of its executive officers under the Incentive Plan. The number of shares of Common Stock issued pursuant to the award will be based on a combination of (i) the Company's total shareholder return ("TSR") and (ii) the Company's relative total shareholder return ("RTSR") for the performance period. Participants will earn from 0% to 200% of the target award based on the Company's TSR and RTSR ranking compared to the TSR 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 three-year performance period, subject to earlier termination of the performance period in the event of a change in control. The grant date fair values were determined using the Monte Carlo simulation method and are being recorded ratably over the performance period.
The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of awards granted during the year ended December 31, 2022:
| | | | | |
Grant date | April 29, 2022 |
Forecast period (years) | 3 |
Risk-free interest rates | 2.9% |
Implied equity volatility | 88.4% |
Stock price on the date of grant | $93.98 |
For grants awarded in the Prior Successor Period, expected volatilities utilized in the Monte Carlo models were estimated using a historical period consistent with the remaining performance period of approximately 3 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 between 0.35% and 0.67% and a range of expected volatilities between 87.0% and 87.1% to estimate the fair value.
Unrecognized compensation expense as of December 31, 2022, related to performance vesting restricted shares was $5.6 million. The expense is expected to be recognized over a weighted average period of 1.71 years.
Predecessor Stock-Based Compensation
The Predecessor granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan (the "2019 Plan"). During the Prior Predecessor Period and the year ended December 31, 2020, the Company’s stock-based compensation cost was $4.4 million and $16.3 million, respectively, of which the Company capitalized $0.9 million and $2.9 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 Prior Predecessor Period and the year ended December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 December 31, 2019 | 4,098,318 | | | $ | 4.73 | | | 1,783,660 | | | $ | 2.96 | |
Granted | 3,069,521 | | | 0.85 | | | — | | | — | |
Vested | (1,294,285) | | | 5.73 | | | — | | | — | |
Forfeited | (4,171,041) | | | 1.68 | | | (943,065) | | | 1.98 | |
Unvested shares as of December 31, 2020 | 1,702,513 | | | $ | 4.74 | | | 840,595 | | | $ | 4.07 | |
Granted | — | | | — | | | — | | | — | |
Vested | (227,132) | | | 8.45 | | | — | | | — | |
Forfeited/canceled | (1,475,381) | | | 4.16 | | | (840,595) | | | 4.07 | |
Unvested shares as of May 17, 2021 | — | | | $ | — | | | — | | | $ | — | |
Predecessor Restricted Stock Units
Restricted stock units awarded under the 2019 Plan generally vested over a period of one year in the case of directors and three years in the case of employees and vesting was 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. All unrecognized compensation expense was recognized as of the Emergence Date.
Predecessor Performance Vesting Restricted Stock Units
The Company previously awarded performance vesting restricted stock units to certain of its executive officers under the 2019 Plan. The number of shares of Common Stock issued pursuant to the award was based on RTSR. RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s TSR ranking compared to the TSR of the companies in the Company’s designated peer group at the end of the performance period. Awards were to 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. All unrecognized compensation expense was recognized as of the Emergence Date.
9.REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil, condensate and NGL. These sales 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.
Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations.
Transaction Price Allocated to Remaining Performance Obligations
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. These contracts typically automatically renew under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, 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 $278.4 million and $232.9 million as of December 31, 2022 and December 31, 2021, respectively, and are reported in accounts receivable - oil and natural gas, and natural gas liquids sales in the accompanying 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 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 each of the periods presented, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
10.LEASES
Nature of Leases
The Company has operating leases on certain equipment with remaining lease durations in excess of one year. The Company recognizes right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than 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 varying terms with third parties to ensure operational continuity, cost control and rig availability in its operations. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year, although at December 31, 2022, the Company had one active long-term drilling rig contract. 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 contract 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, when applicable, 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 drilling costs are borne by other interest owners in our wells.
The Company rents office space for its corporate headquarters, field locations and certain other equipment from third parties, which expire at various dates through 2026. 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. In July 2022, the Company moved its headquarters to a new location. The impact of the Company's new headquarters lease is reflected in the tables below.
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.
Future amounts due under operating lease liabilities as of December 31, 2022, were as follows (in thousands):
| | | | | |
2023 | $ | 13,752 | |
2024 | 13,439 | |
2025 | 836 | |
2026 | 561 | |
2027 | 10 | |
Total lease payments | $ | 28,598 | |
Less: imputed interest | (1,885) | |
Total | $ | 26,713 | |
Lease costs incurred for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period consisted of the following (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 |
Operating lease cost | $ | 535 | | | $ | 48 | | | | $ | 41 | |
Variable lease cost | — | | | 3 | | | | — | |
Short-term lease cost | 31,987 | | | 11,507 | | | | 4,496 | |
Total lease cost(1) | $ | 32,522 | | | $ | 11,558 | | | | $ | 4,537 | |
_____________________(1) The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in either lease operating expenses or general and administrative expenses in the accompanying consolidated statements of operations.
Supplemental cash flow information for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period related to leases was as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 |
Cash paid for amounts included in the measurement of lease liabilities | | | | | | |
Operating cash flows from operating leases | $ | 601 | | | $ | 78 | | | | $ | 48 | |
The weighted-average remaining lease term as of December 31, 2022, was 2.16 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, 2022, was 6.71%.
11.INCOME TAXES
Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables.
The components of income tax benefits and expense were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Current: | | | | | | | | |
State | $ | — | | | $ | (39) | | | | $ | (7,968) | | | $ | — | |
Federal | — | | | — | | | | — | | | (273) | |
Deferred: | | | | | | | | |
State | — | | | — | | | | — | | | 7,563 | |
Federal | — | | | — | | | | — | | | — | |
Total income tax (benefit) expense provision | $ | — | | | $ | (39) | | | | $ | (7,968) | | | $ | 7,290 | |
A reconciliation of the statutory federal income tax amount to the recorded expense follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Income (loss) before federal income taxes | $ | 494,701 | | | $ | (112,868) | | | | $ | 243,026 | | | $ | (1,617,843) | |
Expected income tax at statutory rate | 103,887 | | | (23,702) | | | | 51,036 | | | (339,747) | |
State income taxes | 2,227 | | | (3,177) | | | | (12,484) | | | (14,696) | |
Bankruptcy adjustments | — | | | 44,748 | | | | (111,285) | | | — | |
Remeasurement of state deferred tax asset | 13,869 | | | (7,966) | | | | — | | | — | |
Return to provision | (17,075) | | | — | | | | — | | | — | |
Other differences | 1,117 | | | 2,841 | | | | 445 | | | 10,800 | |
Change in valuation allowance due to current year activity | (104,025) | | | (12,783) | | | | 64,320 | | | 350,933 | |
Income tax (benefit) expense recorded | $ | — | | | $ | (39) | | | | $ | (7,968) | | | $ | 7,290 | |
For the year ended December 31, 2022, the Company's effective tax rate was 0%. For the Prior Predecessor Period, the Company had an effective tax rate of (3.3)% and an income tax benefit of $8.0 million. For the Prior Successor Period, the Company had an effective tax rate of 0.03% and tax benefit of $39 thousand. The higher effective income tax rate for the year ended December 31, 2022, is due the Company recording a benefit in 2021 related to an Oklahoma refund claim associated with an examination of historical returns. The effective tax rate differs from the statutory tax rate due the Company's valuation allowance position.
The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2022, and 2021 are estimated as follows (in thousands):
| | | | | | | | | | | | | | | | |
| Successor | | | |
| December 31, 2022 | | December 31, 2021 | | | | | |
Deferred tax assets: | | | | | | | | |
Net operating loss carryforward and tax credits | $ | 346,455 | | | $ | 298,127 | | | | | | |
Oil and gas property basis difference | 269,206 | | | 432,959 | | | | | | |
Investment in pass through entities | 66,502 | | | 58,751 | | | | | | |
Stock-based compensation expense | 1,484 | | | — | | | | | | |
| | | | | | | | |
| | | | | | | | |
Change in fair value of derivative instruments | 73,198 | | | 86,296 | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Other assets | 52,107 | | | 31,298 | | | | | | |
Total deferred tax assets | 808,952 | | | 907,431 | | | | | | |
Valuation allowance for deferred tax assets | (803,332) | | | (907,358) | | | | | | |
Deferred tax assets, net of valuation allowance | 5,620 | | | 73 | | | | | | |
Deferred tax liabilities: | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Right of use asset | 5,615 | | | — | | | | | | |
Other | 5 | | | 73 | | | | | | |
Total deferred tax liabilities | 5,620 | | | 73 | | | | | | |
Net deferred tax asset | $ | — | | | $ | — | | | | | | |
Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2022. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. On the basis of this evaluation, as of December 31, 2022, a valuation allowance of $803.3 million has been recorded. The amount of the Deferred Tax Asset considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as our projections for growth.
As discussed in Note 2, elements of the Plan provided that the Company’s indebtedness related to Predecessor Senior Notes and certain general unsecured claims were exchanged for Common Stock in settlement of those claims. Absent an exception, a debtor recognizes CODI upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income, but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of CODI and historical interest expense haircut is approximately $655 million, which will reduce the value of the Company’s net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2022. The reduction of net operating losses is expected to be fully offset by a corresponding decrease in valuation allowance. As of December 31, 2021, the Company had an estimated federal net operating loss carryforward of approximately $1.4 billion after giving effect to the estimated reduction in tax attributes as discussed above. Emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. The Company is applying rules under IRC Section 382(l)(5) that allows the Company to mitigate the limitations imposed under the regulations with respect to the Company’s remaining tax attributes. The Company’s deferred tax assets and liabilities, prior to the valuation allowance, have been computed on such basis. Additionally, under IRC Section 382(l)(5), an ownership change subsequent to the Company’s emergence could severely limit or effectively eliminate its ability to realize the value of its tax attributes.
The Company has an available federal tax net operating loss carryforward estimated at approximately $1.6 billion as of December 31, 2022. These federal net operating loss carryforwards of approximately $349 million generated in tax years prior to 2018 will begin to expire in 2036. As a result of the Tax Cuts and Jobs Act, the 2018 through 2022 federal NOL
carryforwards of $1.3 billion have no expiration. The Company also has state net operating loss carryovers of approximately $317 million that began to expire in 2022.
As of December 31, 2022, we had no liability for uncertain tax positions.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022, which, among other things, implements a 15% minimum tax on book income of certain large corporations, a 1% excise tax on net stock repurchases and several tax incentives to promote clean energy. Based on the Company's current analysis of the provisions, the Company does not believe this legislation will have a material impact on its consolidated financial statements.
12.EARNINGS (LOSS) PER SHARE
Basic income or loss per share attributable to common stockholders is computed as (i) net income or loss less (ii) dividends paid to holders of Preferred Stock less (iii) net income or loss attributable to participating securities divided by (iv) weighted average basic shares outstanding. Diluted net income or loss per share attributable to common stockholders is computed as (i) basic net income or loss attributable to common stockholders plus (ii) diluted adjustments to income allocable to participating securities divided by (iii) weighted average diluted shares outstanding. The "if-converted" method is used to determine the dilutive impact for the Company's convertible Preferred Stock and the treasury stock method is used to determine the dilutive impact of unvested restricted stock.
There were 0.2 million shares of restricted stock that were considered dilutive for the year ended December 31, 2022. There were no shares of restricted stock that were considered dilutive for the Prior Successor Period, Prior Predecessor Period or the year ended December 31, 2020. There were 3.7 million and 4.1 million shares of potential common shares issuable due to the Company's Preferred Stock for the year ended December 31, 2022 and Prior Successor Period, respectively. There were 0.1 million shares of restricted stock that were considered anti-dilutive during the Prior Successor Period.
Reconciliations of the components of basic and diluted net income (loss) per common share are presented in the tables below (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Net income (loss) | $ | 494,701 | | | $ | (112,829) | | | | $ | 250,994 | | | $ | (1,625,133) | |
Dividends on Preferred Stock | (5,444) | | | (4,573) | | | | — | | | — | |
Participating securities - Preferred Stock(1) | (76,401) | | | — | | | | — | | | — | |
Net income (loss) attributable to common stockholders | $ | 412,856 | | | $ | (117,402) | | | | $ | 250,994 | | | $ | (1,625,133) | |
Re-allocation of participating securities | 512 | | | — | | | | — | | | — | |
Diluted net income (loss) attributable to common stockholders | $ | 413,368 | | | $ | (117,402) | | | | $ | 250,994 | | | $ | (1,625,133) | |
Basic Shares | 20,185 | | | 20,545 | | | | 160,834 | | | 160,231 | |
Dilutive Shares | 20,347 | | | 20,545 | | | | 160,834 | | | 160,231 | |
Basic EPS | $ | 20.45 | | | $ | (5.71) | | | | $ | 1.56 | | | $ | (10.14) | |
Dilutive EPS | $ | 20.32 | | | $ | (5.71) | | | | $ | 1.56 | | | $ | (10.14) | |
_____________________
(1) Preferred Stock represents participating securities because they participate in any dividends on shares of Common Stock on a pari passu, pro rata basis. However, Preferred Stock does not participate in undistributed net losses.
13.DERIVATIVE INSTRUMENTS
Natural Gas, Oil and NGL Derivative Instruments
The Company seeks to mitigate risks related to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars
and various types of option contracts. These contracts allow the Company to mitigate the impact of declines in future natural gas, oil and NGL prices by effectively locking in floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to the Company in periods of favorable price movements.
The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Gulfport may enter into commodity derivative contracts up to limitations set forth in its Credit Facility. The Company generally enters into commodity derivative contracts for approximately 50% to 75% of its forecasted current year annual production by the end of the first quarter of each fiscal year. The Company typically enters into commodity derivative contracts for the next 12 to 24 months. Gulfport does not enter into commodity derivative contracts for speculative purposes.
The Company does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. Gulfport routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.
Fixed price swaps require that the Company receive a fixed price and pay a floating market price to the counterparty for the hedged community. They 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 Company has entered into natural gas, crude oil and NGL fixed price swap contracts based off the NYMEX Henry Hub, NYMEX WTI and Mont Belvieu C3 indices. Below is a summary of the Company's open fixed price swap positions as of December 31, 2022.
| | | | | | | | | | | | | | | | | |
| Index | | Daily Volume | | Weighted Average Price |
Natural Gas | | | (MMBtu/d) | | ($/MMBtu) |
2023 | NYMEX Henry Hub | | 229,973 | | | $ | 4.28 | |
2024 | NYMEX Henry Hub | | 174,973 | | | $ | 4.41 | |
| | | | | |
Oil | | | (Bbl/d) | | ($/Bbl) |
2023 | NYMEX WTI | | 3,000 | | | $ | 74.47 | |
| | | | | |
NGL | | | (Bbl/d) | | ($/Bbl) |
2023 | Mont Belvieu C3 | | 3,000 | | | $ | 38.07 | |
Each two-way price costless collar has a set floor and ceiling price for the hedged production. They are settled monthly based on differences between the floor and ceiling prices specified in the contract and the referenced settlement price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the collar contracts, the Company will cash-settle the difference with the hedge counterparty. When the referenced settlement price is less than the floor price in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the hedged contract volume. Similarly, when the referenced settlement price exceeds the ceiling price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the hedged contract volume. No payment is due from either party if the referenced settlement price is within the range set by the floor and ceiling prices.
The Company has entered into natural gas costless collar contracts based off the NYMEX Henry Hub natural gas index. Below is a summary of the Company's costless collar positions as of December 31, 2022.
| | | | | | | | | | | | | | | | | | | | | | | |
| Index | | Daily Volume | | Weighted Average Floor Price | | Weighted Average Ceiling Price |
Natural Gas | | | (MMBtu/d) | | ($/MMBtu) | | ($/MMBtu) |
2023 | NYMEX Henry Hub | | 285,000 | | | $ | 2.93 | | | $ | 4.78 | |
2024 | NYMEX Henry Hub | | 90,000 | | | $ | 3.67 | | | $ | 6.87 | |
From time to time the Company has sold natural gas call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps. Each sold call option has an established ceiling price. If at the time of settlement the referenced settlement price exceeds the ceiling price, 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. No payment is due from either party if the referenced settlement price is below the price ceiling. Below is a summary of the Company's open sold call options as of December 31, 2022.
| | | | | | | | | | | | | | | | | |
| Index | | Daily Volume | | Weighted Average Ceiling Price |
Natural Gas | | | (MMBtu/d) | | ($/MMBtu) |
2023 | NYMEX Henry Hub | | 407,925 | | | $ | 2.90 | |
2024 | NYMEX Henry Hub | | 202,000 | | | $ | 3.33 | |
2025 | NYMEX Henry Hub | | 33,315 | | | $ | 4.65 | |
In addition, the Company entered into natural gas basis swap positions. These instruments are arrangements that guarantee a fixed price differential to NYMEX Henry Hub from a specified delivery point. The Company receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity. As of December 31, 2022, the Company had the following natural gas basis swap positions open:
| | | | | | | | | | | | | | | | | | | | | | | |
| Gulfport Pays | | Gulfport Receives | | Daily Volume | | Weighted Average Fixed Spread |
Natural Gas | | | | | (MMBtu/d) | | ($/MMBtu) |
2023 | Rex Zone 3 | | NYMEX Plus Fixed Spread | | 60,000 | | | $ | (0.22) | |
2023 | NGPL TXOK | | NYMEX Plus Fixed Spread | | 20,000 | | | $ | (0.40) | |
2023 | TETCO M2 | | NYMEX Plus Fixed Spread | | 40,082 | | | $ | (1.01) | |
2024 | TETCO M2 | | NYMEX Plus Fixed Spread | | 9,973 | | | $ | (1.03) | |
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 December 31, 2022 and 2021 (in thousands):
| | | | | | | | | | | |
| Successor |
| December 31, 2022 | | December 31, 2021 |
Short-term derivative asset | $ | 87,508 | | | $ | 4,695 | |
Long-term derivative asset | 26,525 | | | 18,664 | |
Short-term derivative liability | (343,522) | | | (240,735) | |
Long-term derivative liability | (118,404) | | | (184,580) | |
Total commodity derivative position | $ | (347,893) | | | $ | (401,956) | |
Gains and Losses
The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and year ended December 31, 2020 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Natural gas derivatives - fair value gains (losses) | $ | 32,797 | | | $ | (223,512) | | | | $ | (123,080) | | | $ | (89,310) | |
Natural gas derivatives - settlement (losses) gains | (1,002,098) | | | (300,172) | | | | (3,362) | | | 113,075 | |
Total (losses) gains on natural gas derivatives | (969,301) | | | (523,684) | | | | (126,442) | | | 23,765 | |
| | | | | | | | |
Oil and condensate derivatives - fair value gains (losses) | 6,618 | | | (5,128) | | | | (6,126) | | | (2,952) | |
Oil and condensate derivatives - settlement (losses) gains | (39,163) | | | (9,720) | | | | — | | | 46,462 | |
Total (losses) gains on oil and condensate derivatives | (32,545) | | | (14,848) | | | | (6,126) | | | 43,510 | |
| | | | | | | | |
NGL derivatives - fair value gains (losses) | 14,648 | | | (5,322) | | | | (4,671) | | | (461) | |
NGL derivatives - settlement losses | (12,549) | | | (12,965) | | | | — | | | (142) | |
Total gains (losses) on NGL derivatives | 2,099 | | | (18,287) | | | | (4,671) | | | (603) | |
| | | | | | | | |
Contingent consideration arrangement - fair value losses | — | | | — | | | | — | | | (1,381) | |
Total (losses) gains on natural gas, oil and NGL derivatives | $ | (999,747) | | | $ | (556,819) | | | | $ | (137,239) | | | $ | 65,291 | |
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 (in thousands):
| | | | | | | | | | | | | | | | | |
| Successor |
| As of December 31, 2022 |
| Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets | | Gross Amounts Subject to Master Netting Agreements | | Net Amount |
Derivative assets | $ | 114,033 | | | $ | (80,345) | | | $ | 33,688 | |
Derivative liabilities | $ | (461,926) | | | $ | 80,345 | | | $ | (381,581) | |
| | | | | | | | | | | | | | | | | |
| Successor |
| As of December 31, 2021 |
| Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets | | Gross Amounts Subject to Master Netting Agreements | | Net Amount |
Derivative assets | $ | 23,359 | | | $ | (20,265) | | | $ | 3,094 | |
Derivative liabilities | $ | (425,315) | | | $ | 20,265 | | | $ | (405,050) | |
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 spread between 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.
14.RESTRUCTURING AND LIABILITY MANAGEMENT EXPENSES
In the third quarter of 2020, the Company announced and completed workforce reductions representing approximately 10% of its headcount. Restructuring charges related to the reduction in workforce primarily consisted of one-time employee-related termination benefits. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability management alternatives during 2020 prior to the filing of the Chapter 11 Cases.
In the third quarter of 2021, the Company announced and completed a workforce reduction representing approximately 3% of its headcount. Charges related to the reduction in workforce primarily consisted of one-time employee-related termination benefits.
The following table summarizes the expenses related to the Company's reductions in workforce as well as expenses incurred related to liability management efforts in the accompanying consolidated statements of operations for the year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and the year ended December 31, 2020 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Reduction in workforce | $ | — | | | $ | 2,858 | | | | $ | — | | | $ | 1,460 | |
Liability management | — | | | — | | | | — | | | 29,387 | |
Total restructuring and liability management expenses | $ | — | | | $ | 2,858 | | | | $ | — | | | $ | 30,847 | |
15.INVESTMENTS
The Company had no investments accounted for by the equity method as of December 31, 2022 and 2021. The following table summarizes the Company's equity investments for the Predecessor Period and the year ended December 31, 2020 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | Carrying Value | | | | | Loss from Equity Method Investments |
| | | | Predecessor | | | | | Predecessor |
| | | | December 31, 2020 | | | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Investment in Grizzly Oil Sands ULC | | | | $ | 24,816 | | | | | | $ | 342 | | | $ | 377 | |
Investment in Mammoth Energy Services, Inc. | | | | — | | | | | | — | | | 10,646 | |
Other equity investments | | | | — | | | | | | — | | | 32 | |
Total equity investments | | | | $ | 24,816 | | | | | | $ | 342 | | | $ | 11,055 | |
Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings, owns an approximate 24.5% interest in Grizzly, a Canadian unlimited liability company. As of December 31, 2022, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company has not paid any cash calls since its decision to cease funding further capital calls in 2019. Grizzly’s functional currency is the Canadian dollar.
Effective as of the Emergence Date, the Company evaluated its investment in Grizzly and determined that the Company no longer has the ability to exercise significant influence over operating and financial policies of Grizzly. As such, the equity method of accounting for its investment was no longer applicable. As a result, the Company will use its previous carrying value of zero (as discussed below) as its initial basis and will subsequently measure at fair value while recording any changes in fair value in earnings.
As discussed in Note 3, the Company reduced the carrying value of its investment in Grizzly to zero upon the Emergence Date. The reduction in valuation was based upon the Company's new management's assessment of the investment and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls, which will lead to further dilution of its equity ownership interest. Mammoth Energy Services, Inc.
As discussed in Note 2, the Company's previously owned shares of the outstanding common stock of Mammoth Energy were used to settle Class 4A claims. The Company's investment carrying value was reduced to zero in the first quarter of 2020 due to the Company's share of cumulative net loss and impairments and the carrying value remained at zero through the Emergence Date.
16.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 (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
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.
Financial assets and liabilities
The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of December 31, 2022 and 2021:
| | | | | | | | | | | | | | | | | |
| Successor |
| December 31, 2022 |
| Level 1 | | Level 2 | | Level 3 |
| (In thousands) |
Assets: | | | | | |
Derivative Instruments
| $ | — | | | $ | 114,033 | | | $ | — | |
Contingent consideration arrangement | $ | — | | | $ | — | | | $ | 4,900 | |
Total assets | $ | — | | | $ | 114,033 | | | $ | 4,900 | |
Liabilities: | | | | | |
Derivative Instruments
| $ | — | | | $ | 461,926 | | | $ | — | |
| | | | | | | | | | | | | | | | | |
| Successor |
| December 31, 2021 |
| Level 1 | | Level 2 | | Level 3 |
| (In thousands) |
Assets: | | | | | |
Derivative Instruments | $ | — | | | $ | 23,359 | | | $ | — | |
Contingent consideration arrangement | $ | — | | | $ | — | | | $ | 5,800 | |
Total assets | $ | — | | | $ | 23,359 | | | $ | 5,800 | |
Liabilities: | | | | | |
Derivative Instruments | $ | — | | | $ | 425,315 | | | $ | — | |
The Company estimates the fair value of all derivative instruments using industry-standard models that considered 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 Company adjusted the fair value of its derivative instruments as a fresh start adjustment at the Emergence Date as a result of changes in the Company's credit adjustment to reflect its new credit standing at emergence.
In January 2020, the Company closed on the sale of its SCOOP water infrastructure assets to a third-party water service provider. The sale included a contingent consideration arrangement, where the company has an opportunity to earn additional incentive payments over the next 13 years, subject to the Company's ability to meet certain thresholds which will be driven by, among other things, the Company's future development program and water production levels. As of December 31, 2022, the fair value of the contingent consideration was $4.9 million, of which $0.6 million is included in prepaid expenses and other assets and $4.3 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company recognized a loss of $0.4 million, gain of $0.4 million and a nominal gain for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period, respectively, with respect to this contingent consideration arrangement. These fair value changes are included in other expense (income) in the accompanying consolidated statements of operations.
Non-financial assets and liabilities
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 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred were $0.1 million, $0.2 million and $0.5 million for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period, respectively. Fair value of other financial instruments
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's Credit Facility is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.
Chapter 11 Emergence and Fresh Start Accounting
On the Emergence Date, the Company adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of May 17, 2021. The inputs utilized in the valuation of the Company’s most significant asset, its oil and natural gas properties and related assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of May 17, 2021, operating and development costs, expected future development plans for the properties and discount rates based on a weighted-average cost of capital computation. The Company also recorded its asset retirement obligations at fair value as a result of fresh start accounting. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of the Emergence Date, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk free rate to discount such costs. Refer to Note 3 for a detailed discussion of the fair value approaches used by the Company.
17.RELATED PARTY TRANSACTIONS
In the ordinary course of business, the Company has conducted business activities with certain related parties.
As discussed in Note 2, the Company's previously owned shares of the outstanding common stock of Mammoth Energy were used to settle Class 4A claims in 2021. As of December 31, 2022 and 2021, the Company held no shares of Mammoth Energy's outstanding common stock. As of December 31, 2020, the Company owned approximately 21.5% of Mammoth Energy's outstanding common stock. There were no material amounts of services provided by Mammoth Energy that were included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2022 and 2021 and $0.6 million for the year ended December 31, 2020. 18.COMMITMENTS
Firm Transportation and Gathering Agreements
The Company has contractual commitments with midstream and pipeline companies for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing the cost of these commitments. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, costs associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves.
A summary of these commitments at December 31, 2022, are set forth in the table below, excluding contracts in the process of being rejected as discussed in the Litigation and Regulatory Proceedings section in Note 19 (in thousands): | | | | | | | | | |
2023 | | | $ | 231,123 | |
2024 | | | 220,790 | |
2025 | | | 139,788 | |
2026 | | | 136,317 | |
2027 | | | 138,485 | |
Thereafter | | | 751,882 | |
Total | | | $ | 1,618,385 | |
Other Operational Commitments
The Company has entered into various contractual commitments to purchase inventory and other material to be used in future activities during the year ended December 31, 2022. The Company's commitment to purchase these materials spans 2023 and 2024, with approximately $52.7 million in commitments in 2023 and $31.2 million for 2024.
Future Sales Commitments
The Company has entered into various firm sales contracts with third parties to deliver and sell natural gas. The Company expects to fulfill its delivery commitments primarily with production from proved developed reserves. The Company's proved reserves have generally been sufficient to satisfy its delivery commitments during the three most recent years, and it expects such reserves will continue to be the primary means of fulfilling its future commitments. However, where the Company's proved reserves are not sufficient to satisfy its delivery commitments, it can and may use spot market purchases of third-party production to satisfy these commitments. The Company's commitments as of December 31, 2022, were 20,000 MMBtu per day and extend through March 2024.
Contributions to 401(k) Plan
Gulfport sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum pre-tax threshold through salary deferrals. The plan is considered a Safe Harbor 401(k) and provides a company
match on 100% of salary deferrals that do not exceed 4% of compensation in addition to a match of 50% of salary deferrals that exceed 4% but do not exceed 6% of compensation. The Company may also make discretionary elective contributions to the plan. Effective January 1, 2023, the Company increased the match for all employees on 100% of salary deferrals that do not exceed 6% of compensation. The following table summarizes the contributions expenses related to this plan for the year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and the year ended December 31, 2020 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Contributions expense | $ | 1,386 | | | $ | 683 | | | | $ | 721 | | | $ | 2,600 | |
19.CONTINGENCIES
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. In accordance with ASC Topic 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.
Litigation and Regulatory Proceedings
As part of its Chapter 11 Cases and restructuring efforts as discussed in Note 2, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation ("TC") and Rover Pipeline LLC ("Rover") (jointly, the “Pending Motions to Reject”). During the third quarter of 2021, Gulfport finalized a settlement agreement with TC that was approved by the Bankruptcy Court on September 21, 2021. Pursuant to the settlement agreement, Gulfport and TC agreed that the firm transportation contracts between Gulfport and TC would be rejected without any further payment or obligation by Gulfport or TC, and TC assigned its damages claims from such rejection to Gulfport. In exchange, Gulfport agreed to make a payment of $43.8 million in cash to TC. The $43.8 million was paid to TC on October 7, 2021. Gulfport expects to receive distributions for a significant portion of such amounts through future distributions with respect to the assigned claims pursuant to the terms of the Plan that became effective in May 2021. Any future distributions will be recognized once received by Gulfport. In February 2022, Gulfport received an initial distribution of $11.5 million from the above-mentioned claim, which is included in Other, net in the accompanying consolidated statements of operations. Gulfport finalized a settlement agreement with Rover that was approved by the Bankruptcy Court on February 21, 2023. Pursuant to the settlement agreement, Gulfport and Rover agreed that the firm transportation contracts between Gulfport and Rover would be rejected. The Bankruptcy Court Order provided Rover will: (a) receive an allowed $85.9 million Class 4A General Unsecured Claim (the “Rover Unsecured Claim”), (b) receive an administrative claim of $1.0 million payable by Gulfport, and (c) draw the full amount of its credit assurance. Gulfport paid the $1.0 million administrative claim, and has no further obligations to Rover; the Rover Unsecured Claim will receive distributions under the Plan payable from the liquidating trust, not Gulfport. On February 24, 2023, Gulfport received a $17.8 million interim distribution for its TC claim. The timing and amount of any future distributions to Gulfport are not certain, and the total amount received will be impacted by the liquidating trust’s distributions and resolution of other remaining bankruptcy claims.
The Company has been named as a defendant in three separate complaints, two filed by Siltstone Resources, LLC, and the third filed by the Ohio Public Works Commission (OPWC) (together, the "Complaints"). The Complaints all arise from restrictive covenants in favor of OPWC generally prohibiting any transfer and any use inconsistent with a green park space. OPWC filed crossclaims against Gulfport in the Siltstone matters alleging that the transfer of the mineral rights and the development of oil and gas on the property violated these restrictive covenants. On June 19, 2018, October 25, 2019, and March 15, 2019, each trial court in the Complaints entered judgment in favor of the Company and other defendants, finding the restrictive covenants only applied to the surface estate. OPWC appealed each judgement to the respective Ohio Courts of Appeal where the trial court decisions were reversed in favor of OPWC. The Company and certain other parties to the Complaints appealed the appellate court decisions to the Ohio Supreme Court. On February 23, 2022, the Ohio Supreme Court affirmed the first appellate decision and remanded the case back to the trial court. On December 27, 2022, the Ohio Supreme
Court affirmed the other two complaints and remanded the matters back to the trial court. OPWC is seeking both injunctive relief to enforce the restrictive covenants and equitable relief. Liquidated damages were successfully discharged in the Company’s Chapter 11 proceedings through May 17, 2021. The scope and consequence of any injunctive relief that may be granted is not certain, but may have an adverse impact on the Company's operations associated with the leases subject to the Complaints.
The Company, along with other oil and gas companies, have been named as a defendant in J&R Passmore, LLC, individually and on behalf of all others similarly situated, in the United States District Court for the Southern District of Ohio on December 6, 2018. Plaintiffs assert their respective leases are limited to the Marcellus and Utica shale geological formations and allege that Defendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. Plaintiffs seek the full value of any production from below the Marcellus and Utica shale formations, unspecified damages from the diminution of value to their mineral estate, unspecified punitive damages, and the payment of reasonable attorney fees, legal expenses, and interest. On April 27, 2021, the Bankruptcy Court for the Southern District of Texas approved a settlement agreement in which the plaintiffs fully released the Company from all claims for amounts allegedly owed to the plaintiffs through the effective date of the Company’s Chapter 11 plan, which occurred on May 17, 2021. The plaintiffs are continuing to pursue alleged damages after May 17, 2021.
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. Gulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. The Company conducts 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.
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.
Concentration of Credit Risk
Gulfport operates in the oil and natural gas industry principally in the states of Ohio and Oklahoma with sales to refineries, re-sellers such as marketers, and other end users. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term.
The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation. At December 31, 2022, Gulfport held no cash in excess of insured limits in these banks.
During the year ended December 31, 2022, two customers accounted for approximately 31% of the Company's total sales. During the Prior Successor Period, two customers accounted for approximately 30% of the Company's total sales. During the Prior Predecessor Period, three customers accounted for approximately 37% of the Company's total sales. During the year ended December 31, 2020, one customer accounted for approximately 12% of the Company's total sales. The Company does not believe that the loss of any of these customers would have a material adverse effect on its natural gas, oil and condensate and NGL sales as alternative customers are readily available.
20.SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
The Company is making the following supplemental disclosures of oil and gas activities, in accordance with the full cost method of accounting for its oil and gas exploration and development activities. The Company owns a 24.5% interest in Grizzly. However, Grizzly did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below.
The following table provides historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States:
Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)
| | | | | | | | | | | |
| Successor |
| Year Ended December 31, 2022 | | Year Ended December 31, 2021 |
Proved properties | $ | 2,418,666 | | | $ | 1,917,833 | |
Unproved properties | 178,472 | | | 211,007 | |
Total oil and natural gas properties | 2,597,138 | | | 2,128,840 | |
Accumulated depletion, amortization and impairment | (543,780) | | | (277,331) | |
Net capitalized costs | $ | 2,053,358 | | | $ | 1,851,509 | |
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Costs Incurred in Oil and Gas Property Acquisition and Development Activities (in thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Acquisition | $ | 29,675 | | | $ | 13,411 | | | | $ | 3,922 | | | $ | 15,260 | |
Development | 441,458 | | | 191,193 | | | | 112,986 | | | 276,622 | |
Exploratory | — | | | — | | | | — | | | — | |
Total | $ | 471,133 | | | $ | 204,604 | | | | $ | 116,908 | | | $ | 291,882 | |
Capitalized interest is included as part of the cost of oil and natural gas properties. The Company did not capitalize interest expense for the year ended December 31, 2022 or Prior Predecessor Period, and capitalized $0.2 million and $0.9 million during the Prior Successor Period and year ended December 31, 2020, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $20.2 million, $11.9 million, $8.0 million and $25.0 million during the year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and year ended December 31, 2020, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.
Results of Operations for Producing Activities (in thousands)
The following table sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production. | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Period from May 18, 2021 through December 31, 2021 | | | Period from January 1, 2021 through May 17, 2021 | | Year Ended December 31, 2020 |
Revenues | $ | 2,330,859 | | | $ | 1,092,584 | | | | $ | 410,276 | | | $ | 801,251 | |
Production costs | (482,175) | | | (274,428) | | | | (192,959) | | | (537,609) | |
Depletion | (266,449) | | | (159,518) | | | | (60,831) | | | (229,702) | |
Impairment | — | | | (117,813) | | | | — | | | (1,357,099) | |
Income tax benefit (expense) | — | | | 39 | | | | 7,968 | | | (7,290) | |
Results of operations from producing activities | $ | 1,582,235 | | | $ | 540,864 | | | | $ | 164,454 | | | $ | (1,330,449) | |
Depletion per Mcf of gas equivalent (Mcfe) | $ | 0.74 | | | $ | 0.69 | | | | $ | 0.45 | | | $ | 0.61 | |
Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2022, 2021 and 2020 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2022, 2021 and 2020, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2022 reserve report are $94.14 per barrel of oil, $6.36 per MMbtu and $47.86 per barrel for NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2021 and 2020 for reserve report purposes are $66.55 per barrel, $3.60 per MMbtu and $31.90 per barrel for NGL and $39.54 per barrel, $1.99 per MMbtu and $15.40 per barrel for NGL, respectively.
Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.
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| Oil (MMBbl) | | Natural Gas (Bcf) | | | NGL (MMBbl) | | Natural Gas Equivalent (Bcfe) |
Proved Reserves | | | | | | | | |
December 31, 2019 (Predecessor) | 18 | | | 4,048 | | | | 62 | | | 4,528 | |
Purchases of reserves | — | | | — | | | | — | | | — | |
Extensions and discoveries | 1 | | | 216 | | | | 3 | | | 240 | |
Sales of reserves | — | | | (74) | | | | — | | | (75) | |
Revisions of prior reserve estimates | (4) | | | (1,564) | | | | (23) | | | (1,725) | |
Current production | (2) | | | (345) | | | | (4) | | | (380) | |
December 31, 2020 (Predecessor) | 13 | | | 2,281 | | | | 38 | | | 2,588 | |
Purchases of reserves | — | | | — | | | | — | | | — | |
Extensions and discoveries | 2 | | | 617 | | | | 11 | | | 695 | |
Sales of reserves | — | | | — | | | | — | | | — | |
Revisions of prior reserve estimates | 2 | | | 913 | | | | 9 | | | 982 | |
Current production | (2) | | | (333) | | | | (4) | | | (366) | |
December 31, 2021 (Successor) | 16 | | | 3,478 | | | | 54 | | | 3,898 | |
Purchases of reserves | — | | | — | | | | — | | | — | |
Extensions and discoveries | 3 | | | 391 | | | | 5 | | | 439 | |
Sales of reserves | — | | | — | | | | — | | | — | |
Revisions of prior reserve estimates | — | | | 66 | | | | — | | | 70 | |
Current production | (2) | | | (322) | | | | (4) | | | (359) | |
December 31, 2022 (Successor) | 18 | | | 3,612 | | | | 54 | | | 4,048 | |
Proved developed reserves | | | | | | | | |
December 31, 2019 (Predecessor) | 8 | | | 1,757 | | | | 30 | | | 1,984 | |
December 31, 2020 (Predecessor) | 7 | | | 1,358 | | | | 22 | | | 1,527 | |
December 31, 2021 (Successor) | 8 | | | 1,928 | | | | 31 | | | 2,165 | |
December 31, 2022 (Successor) | 9 | | | 2,034 | | | | 34 | | | 2,295 | |
Proved undeveloped reserves | | | | | | | | |
December 31, 2019 (Predecessor) | 10 | | | 2,291 | | | | 32 | | | 2,544 | |
December 31, 2020 (Predecessor) | 7 | | | 923 | | | | 16 | | | 1,061 | |
December 31, 2021 (Successor) | 8 | | | 1,550 | | | | 22 | | | 1,733 | |
December 31, 2022 (Successor) | 9 | | | 1,578 | | | | 20 | | | 1,752 | |
Totals may not sum or recalculate due to rounding. | | | | | | | | |
In 2022, the Company experienced extensions of 438.9 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions, 295.9 Bcfe was attributable to the addition of 36 PUD locations in the Utica, 72.1 Bcfe was attributable to the addition of 8 PUD locations in the Marcellus and 65.4 Bcfe was attributable to the addition of 5 PUD locations in the SCOOP. The 8 Marcellus PUD locations added during 2022 have been grouped into the Utica for this report. The Company experienced total upward revisions of approximately 69.7 Bcfe in estimated proved reserves, of which 47.7 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $3.60 per MMBtu for 2021 to $6.36 per MMBtu for 2022, the 12-month average price for NGL increased from $31.90 per barrel for 2021 to $47.86 per barrel for 2022, and the 12-month average price for crude oil increased from $66.55 per barrel for 2021 to $94.14 per barrel for 2022. Upward revisions of 144.5 Bcfe were a result of an increase in working interest and net revenue interests as a result of our successful leasing efforts through 2022. Downward revisions of 95.6 Bcfe were experienced as a result of the SEC five-year development window, which removed 4 PUD locations in the Utica and 5 PUD locations in the SCOOP. The development plan changes reflect our commitment to optimizing the long-term development schedule to maximize cash flow and overall economic returns. A small downward revision of 26.9 Bcfe was primarily a result of performance changes to several wells and changes in PUD location forecasts.
In 2021, the Company experienced extensions of 694.6 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreage. Of the total extensions, 352.2 Bcfe was attributable to the addition of 29 PUD locations in the Utica, 342.2 Bcfe was attributable to the addition of 34 PUD locations in the SCOOP. The Company experienced total upward revisions of approximately 982.2 Bcfe in estimated proved reserves, of which 889.2 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $1.99 per MMBtu for 2020 to $3.60 per MMBtu for 2021, the 12-month average price for NGL increased from $15.40 per barrel for 2020 to $31.90 per barrel for 2021, and the 12-month average price for crude oil increased from $39.54 per barrel for 2020 to $66.55 per barrel for 2021. Upward revisions of 157.6 Bcfe were experienced from a combination of well performance, operating and development cost improvements and working interest changes. This was partially offset by a downward revision of 64.6 Bcfe, which was primarily a result of the exclusion of 4 PUD locations in the Utica when changes in the Company's schedule moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment to capital discipline, funding future activities within cash flow and ongoing optimization of our development plan. Finally, during 2021, we sold approximately 0.2 Bcfe of proved oil and natural gas reserves through various sales of our non-operated interests in our other non-core assets.
In 2020, the Company experienced extensions of 239.8 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreage. Of the total extensions, 150.6 Bcfe was attributable to the addition of 14 PUD locations in the Utica, 87.8 Bcfe was attributable to the addition of eight PUD locations in the SCOOP. The Company experienced total downward revisions of approximately 1.7 Tcfe in estimated proved reserves, of which 1,268.4 Bcfe was the result of commodity price changes. Commodity prices experienced volatility throughout 2020 and the 12-month average price for natural gas decreased from $2.58 per MMBtu for 2019 to $1.99 per MMBtu for 2020, the 12-month average price for NGL decreased from $21.25 per barrel for 2019 to $15.40 per barrel for 2020, and the 12-month average price for crude oil decreased from $55.85 per barrel for 2019 to $39.54 per barrel for 2020. An additional 720.3 Bcfe in downward revisions was a result of the exclusion of 48 PUD locations in the Utica and 31 PUD locations in the SCOOP, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflected the Company's commitment to capital discipline, funding future activities within cash flow and ongoing optimization of our development plan. Positive revisions of 263.8 Bcfe were experienced from a combination of operating and development cost improvements, well performance and working interest changes.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2022, 2021 and 2020 using an unweighted average first-of-the-month price for the period January through December 31, 2022, 2021 and 2020. The average gas prices used were $6.36, $3.60 and $1.99 for the periods ended December 31, 2022, 2021 and 2020, respectively. The average oil prices used were $94.14, $66.55 and $39.54, for the periods ended December 31, 2022, 2021 and 2020, respectively. The average NGL prices used were $47.86, $31.90 and $15.40, for the periods ended December 31, 2022, 2021 and 2020, respectively.
Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved developed non-producing and proved undeveloped reserves are approximately $396.7 million in 2023, $315.6 million in 2024 and $243.4 million in 2025. Estimated future development costs include capital spending on major development projects. Gulfport believes cash flow from its operating activities, cash on hand and borrowings under its Credit Facility will be sufficient to cover these estimated future development costs.
The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating Gulfport or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:
•Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
•Future operating and capital costs will likely differ from those required to be used in these calculations and do not reflect cost savings of Company owned midstream operations on future operating expenses.
•Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and condensate and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
•Future revenues may be subject to different production, severance and property taxation rates.
•The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
The following table summarizes estimated future net cash flows from natural gas and crude oil reserves (in millions):
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Year Ended December 31, 2021 | | | Year Ended December 31, 2020 |
Future cash flows | $ | 26,677 | | | $ | 14,938 | | | | $ | 4,079 | |
Future development and abandonment costs | (1,588) | | | (1,141) | | | | (652) | |
Future production costs | (5,872) | | | (5,227) | | | | (2,325) | |
Future production taxes | (553) | | | (336) | | | | (137) | |
Future income taxes | (2,609) | | | (437) | | | | — | |
Future net cash flows | 16,055 | | | 7,797 | | | | 965 | |
10% discount to reflect timing of cash flows | (7,776) | | | (3,659) | | | | (425) | |
Standardized measure of discounted future net cash flows | $ | 8,279 | | | $ | 4,138 | | | | $ | 540 | |
Future development and abandonment costs include not only development costs but also all future costs to settle asset retirement obligations. The following table summarizes the total of all future costs to settle asset retirement obligations that are included in future development and abandonment costs above (in millions):
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Year Ended December 31, 2021 | | | Year Ended December 31, 2020 |
Future asset retirement obligations | $ | 222 | | | $ | 205 | | | | $ | 120 | |
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The principal source of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below (in millions):
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2022 | | Year Ended December 31, 2021 | | | Year Ended December 31, 2020 |
Sales and transfers of oil and gas produced, net of production costs | $ | (1,849) | | | $ | (1,035) | | | | $ | (264) | |
Net changes in prices, production costs, and development costs | 5,130 | | | 2,596 | | | | (954) | |
| | | | | | |
Extensions and discoveries | 941 | | | 639 | | | | 38 | |
Previously estimated development costs incurred during the period | 204 | | | 149 | | | | 215 | |
Revisions of previous quantity estimates, less related production costs | 154 | | | 858 | | | | (255) | |
Sales of oil and gas reserves in place | (1) | | | (1) | | | | (6) | |
Accretion of discount | 414 | | | 54 | | | | 170 | |
Net changes in income taxes | (1,067) | | | (178) | | | | — | |
Change in production rates and other | 215 | | | 516 | | | | (109) | |
Total change in standardized measure of discounted future net cash flows | $ | 4,141 | | | $ | 3,598 | | | | $ | (1,165) | |
21.SUBSEQUENT EVENTS
Natural gas, Oil and NGL Derivative Instruments
Subsequent to December 31, 2022 and as of February 23, 2023, the Company entered into the following derivative contracts:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Period | | Type of Derivative Instrument | | Index | | Daily Volume (MMBtu) | | Weighted Average Price |
2023 | | Basis Swaps | | TETCO M2 | | 76,219 | | | $(0.85) |
2023 | | Basis Swaps | | Rex Zone 3 | | 59,452 | | | $(0.22) |
2023 | | Basis Swaps | | NGPL TXOK | | 42,685 | | | $(0.34) |
2024 | | Swaps | | NYMEX Henry Hub | | 30,000 | | | $3.90 |
2024 | | Costless Collars | | NYMEX Henry Hub | | 60,000 | | | $3.17 / $3.96 |
Additionally, subsequent to year end, the Company restructured a portion of its natural gas sold call position by buying back a portion of its 2023 natural gas sold call position, and selling additional natural gas calls for 2023 and 2025. The following table summarizes these transactions:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Period | | Type of Derivative Instrument | | Index | | Daily Volume (MMBtu) | | Weighted Average Price |
2023 | | Purchased Gas Call Options | | NYMEX Henry Hub | | 134,137 | | | $2.90 |
2023 | | Sold Gas Call Options | | NYMEX Henry Hub | | 134,137 | | | $3.70 |
2025 | | Sold Gas Call Options | | NYMEX Henry Hub | | 160,000 | | | $6.04 |
Expanded Common Stock Repurchase Program
On February 27, 2023, the Company's Board of Directors approved an increase to the authorized common stock repurchase amounts under its Repurchase Program from $300 million to $400 million. The additional $100 million authorization expires on March 31, 2024.