Exhibit 99.2
Maverick Natural Resources, LLC and Subsidiaries
Unaudited Consolidated Financial Statements
As of September 30, 2024 and December 31, 2023 and for the nine-month periods ended September 30, 2024 and 2023
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Consolidated Financial Statements (Unaudited)
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| Balance Sheets | 3 |
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| Statements of Operations | 4 |
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| Statements of Members’ Equity | 5 |
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| Statements of Cash Flows | 6 |
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| Notes to Financial Statements | 7–30 |
| Thousands of dollars | | September 30, 2024 | | | December 31, 2023 | |
| Assets | | | | | | |
| Current assets | | | | | | |
| Cash | | $ | 40,137 | | | $ | 53,263 | |
| Restricted cash - current | | | 36,736 | | | | 31,936 | |
| Accounts receivable, net | | | 127,889 | | | | 140,260 | |
| Derivative instruments | | | 37,581 | | | | 46,503 | |
| Inventory | | | 9,666 | | | | 2,209 | |
| Prepaid expenses and other current assets | | | 6,535 | | | | 7,089 | |
| Total current assets | | | 258,544 | | | | 281,260 | |
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| Property, plant and equipment | | |
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| Oil and natural gas properties | | | 2,391,401 | | | | 2,674,820 | |
| Other property, plant and equipment | | | 119,920 | | | | 110,888 | |
| Property, plant and equipment | | | 2,511,321 | | | | 2,785,708 | |
| Accumulated depletion, depreciation, and impairment | | | (1,047,475 | ) | | | (1,097,788 | ) |
| Property, plant and equipment, net | | | 1,463,846 | | | | 1,687,920 | |
| Other long-term assets | | |
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| Assets held-for-sale - noncurrent | | | 90,291 | | | | – | |
| Derivative instruments | | | 23,151 | | | | 48,018 | |
| Operating lease right-of-use assets | | | 11,534 | | | | 12,362 | |
| Other long-term assets | | | 33,260 | | | | 35,577 | |
| Total assets | | $ | 1,880,626 | | | $ | 2,065,137 | |
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| Liabilities and Equity | | | | | | | | |
| Current liabilities | | | | | | | | |
| Accounts payable and accrued expenses | | $ | 220,839 | | | $ | 272,637 | |
| Current portion of long-term debt | | | 110,254 | | | | 113,773 | |
Derivative instruments
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| Current portion of asset retirement obligation | | | 7,282 | | | | 7,282 | |
| Operating lease obligations - current | | | 1,477 | | | | 841 | |
| Liabilities related to assets held-for-sale | | | 13,401 | | | | – | |
| Total current liabilities | | | 353,253 | | | | 394,631 | |
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| Long-term debt | | | 657,292 | | | | 697,405 | |
| Derivative instruments | | | 548 | | | | 3,994 | |
| Asset retirement obligation | | | 226,248 | | | | 242,391 | |
| Operating lease obligations - noncurrent | | | 24,932 | | | | 25,316 | |
| Liabilities related to assets held-for-sale - noncurrent | | | 16,957 | | | | – | |
| Other long-term liabilities | | | 29,785 | | | | 29,501 | |
| Total liabilities | | | 1,309,015 | | | | 1,393,238 | |
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| Members' equity | | | 571,611 | | | | 671,899 | |
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| Total liabilities and equity | | $ | 1,880,626 | | | $ | 2,065,137 | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | Year to Date | | | Year to Date | |
| Thousands of dollars | | September 30, 2024 | | | September 30, 2023 | |
| Revenues and other income items | | | | | | |
| Oil revenues | | $ | 421,209 | | | $ | 465,331 | |
| Natural gas revenues | | | 77,601 | | | | 119,439 | |
| NGL revenues | | | 78,111 | | | | 85,248 | |
| Oil, natural gas and NGL revenues | | | 576,921 | | | | 670,018 | |
| Loss on commodity derivative instruments | | | (2,322 | ) | | | (27,341 | ) |
| Other revenues, net | | | 60,881 | | | | 65,067 | |
| Total revenues and other income items | | | 635,480 | | | | 707,744 | |
| Operating costs and expenses | | | | | | | | |
| Operating costs | | | 353,810 | | | | 372,859 | |
| Depletion, depreciation and amortization | | | 130,491 | | | | 119,186 | |
| Impairment of oil and natural gas properties | | | 110,856 | | | | 62,683 | |
| General and administrative expenses | | | 45,638 | | | | 55,010 | |
| Restructuring costs | | | 8,822 | | | | 1,600 | |
| Gain on sale of assets | | | (2,206 | ) | | | (1,022 | ) |
| Total operating costs and expenses | | | 647,411 | | | | 610,316 | |
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| Operating income (loss) | | | (11,931 | ) | | | 97,428 | |
| Interest expense | | | 63,558 | | | | 41,810 | |
| Other income, net | | | (2,680 | ) | | | (842 | ) |
| Total other expense (income) | | | 60,878 | | | | 40,968 | |
| Income (loss) before taxes | | | (72,809 | ) | | | 56,460 | |
| Income tax expense (benefit) | | | 148 | | | | (416 | ) |
| Net income (loss) | | $ | (72,957 | ) | | $ | 56,876 | |
The accompanying notes are an integral part of these consolidated financial statements.
| | Outstanding | | | Total Members' | |
| Thousands of dollars | | Common Units | | | Equity | |
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| Balances, December 31, 2022 | | | 2,896 | | | $ | 755,148 | |
Unit-based compensation | | | – | | | | (410 | ) |
Units issued under unit-based compensation awards, net of tax withholdings | | | 2 | | | | 1,321 | |
Net income (loss) | | | – | | | | 56,876 | |
Redemption of units | | | (1 | ) | | | (1,538 | ) |
Distributions | | | – | | | | (80,000 | ) |
Other | | | – | | | | (220 | ) |
| Balances, September 30, 2023 | | | 2,897 | | | | 731,177 | |
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| Balances, December 31, 2023 | | | 2,897 | | | | 671,899 | |
Units issued under unit-based compensation awards, net of tax withholdings | | | 5 | | | | 3,092 | |
Net loss | | | – | | | | (72,957 | ) |
Redemption of units | | | (1 | ) | | | (1,145 | ) |
Unit-based compensation modified to liability awards | | | (9 | ) | | | (4,682 | ) |
Distributions | | | – | | | | (24,242 | ) |
Other | | | – | | | | (354 | ) |
| Balances, September 30, 2024 | | | 2,892 | | | | 571,611 | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | Nine Months Ended September 30, | |
| Thousands of dollars | | 2024 | | | 2023 | |
| Cash flows from operating activities | | | | | | |
| Net income (loss) | | $ | (72,957 | ) | | $ | 56,876 | |
| Adjustments to reconcile cash flow from operating activities: | | | | | | | | |
| Depletion, depreciation and amortization | | | 130,491 | | | | 119,186 | |
| Impairment of oil and natural gas properties | | | 110,856 | | | | 62,683 | |
| (Gain) loss on derivative instruments | | | 2,322 | | | | 27,341 | |
| Derivative instrument settlement payments | | | 27,923 | | | | (34,819 | ) |
| Deferred income taxes | | | - | | | | (397 | ) |
| Gain on sale of assets | | | (2,206 | ) | | | (1,022 | ) |
| Restructuring costs, net of payments | | | 2,498 | | | | 93 | |
| Write off of debt issuance costs | | | 1,556 | | | | 3,678 | |
| Other | | | 8,672 | | | | 1,520 | |
| Changes in assets and liabilities: | | | | | | | | |
| Accounts receivable and other assets | | | 2,737 | | | | 47,961 | |
| Inventory | | | (2,352 | ) | | | (1,615 | ) |
| Accounts payable and accrued expenses | | | (29,048 | ) | | | (53,687 | ) |
| Net cash provided by operating activities | | | 180,492 | | | | 227,798 | |
| Cash flows from investing activities | | | | | | | | |
| Capital acquisitions, net | | | (14,683 | ) | | | (17,367 | ) |
| Capital expenditures | | | (104,416 | ) | | | (227,185 | ) |
| Proceeds from sale of assets | | | 1,799 | | | | 15,514 | |
| Net cash used in investing activities | | | (117,300 | ) | | | (229,038 | ) |
| Cash flows from financing activities | | |
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| Distributions to common unitholders | | | (24,242) | | | | (80,000) | |
| Credit facility borrowings | | | 160,500 | | | | 315,000 | |
| Repayments of credit facility | | | (126,500 | ) | | | (245,000 | ) |
| Issuance of term debt | | | 10,000 | | | | - | |
| Repayments of term debt | | | (88,464 | ) | | | - | |
| Long-term debt issuance costs | | | - | | | | (114 | ) |
| Redemption of common units | | | (1,928 | ) | | | (1,538 | ) |
| Principal payments on finance lease obligations | | | (884 | ) | | | (672 | ) |
| Net cash used in financing activities | | | (71,518 | ) | | | (12,324 | ) |
| Increase (decrease) in cash and restricted cash | | | (8,326 | ) | | | (13,564 | ) |
| Cash and restricted cash - beginning of period | | | 85,199 | | | | 16,806 | |
| Cash and restricted cash - end of period | | $ | 76,873 | | | $ | 3,242 | |
The accompanying notes are an integral part of these consolidated financial statements.
Maverick Natural Resources, LLC (“MNR” or “Parent”) and its subsidiaries, including Maverick Asset Holdings LLC (“MAH”), Maverick ABS Holdco, LLC (“ABS Holdco”), and Maverick Services, LLC (“MAV Services”), (collectively, “Maverick,” “we” or the “Company”) is a Delaware limited liability company formed on March 22, 2018. We are a Houston, Texas-based oil and natural gas company focused on the development and production of long-lived oil and natural gas reserves throughout the United States. Our primary operations are in seven regions in the United States: East Texas, Mid-Continent (Western Oklahoma and Eastern New Mexico); Permian (West Texas); Rockies (Wyoming); Southeast (Southwest Florida, Florida Panhandle and Alabama); and Western Anadarko (Texas Panhandle and Southwestern Oklahoma).
On October 26, 2023, the Parent, through its consolidated subsidiaries, raised $640 million through an asset-backed securitization financing transaction.
Several new subsidiaries were created including MNR ABS Holdings I, LLC (“ABS Holdings”) and MNR ABS Issuer I, LLC (“ABS Issuer”). See Note 4 – Acquisitions, Divestitures, and Assets Held for Sale – Transactions Between Entities Under Common Control and Note 9 – Debt for further discussion.
In January 2025, the Company entered into a definitive merger agreement with Diversified Energy Company PLC (“Diversified”), pursuant to which Diversified will acquire all the outstanding equity interest of the Company. For additional information, see Note 14 – Subsequent Events.
The Company operates its properties through its primary operating subsidiaries: Breitburn Operating, L.P. (“BOLP”), Unbridled Resources, LLC (“Unbridled”), and Maverick Permian, LLC.
In addition to our operating companies, the Company’s subsidiaries include: (i) Wheeler Midstream, LLC, an oil terminal located in Wheeler County, TX, which purchases oil from both properties operated by Unbridled, a wholly owned entity, and third-party operated properties, (ii) MidPoint Midstream, LLC, a gas gathering operation located in Wheeler and Hemphill Counties, Texas and Roger Mills and Beckham Counties, Oklahoma, which gathers and compresses natural gas produced from Unbridled and third party operated properties, and (iii) Bluebonnet Resources, LLC, which acquired unproved acreage for development purposes.
| 2. | Summary of Significant Accounting Policies |
Basis of Presentation and Principles of Consolidation
Our unaudited consolidated financial statements relate to our financial position as of September 30, 2024 and December 31, 2023, and our results of operations for the nine months ended September 30, 2024 and September 30, 2023, respectively. They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted, although the Company believes that the disclosures are adequate to make the information presented not misleading. Our consolidated financial statements include Maverick and our wholly owned or majority-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Recently Adopted Accounting Standards
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13’’), which changes the impairment model for most financial assets. The ASU introduces a new credit loss methodology, Current Expected Credit Losses (CECL), which requires earlier recognition of credit losses, while also providing additional transparency about credit risk. Since its original issuance in 2016, the FASB has issued several updates to the original ASU. The CECL framework utilizes a lifetime “expected credit loss” measurement objective for the recognition of credit losses for loans, held-to-maturity securities, and other receivables at the time the financial asset is originated or acquired. The expected credit losses are adjusted each period for changes in expected lifetime credit losses. The methodology replaces the multiple existing impairment methods, which generally require that a loss be incurred before it is recognized.
On January 1, 2023, the Company adopted the guidance applying the modified retrospective basis approach. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements as of the adoption date, January 1, 2023.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), which provided optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that referenced LIBOR ("London Inter-Bank Offered Rate") or another rate. ASU 2020-04 was in effect through December 31, 2022. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. In December 2022, the FASB issued ASU 2022-06, "Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848" ("ASU 2022-06"), which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. As of September 30, 2024, the Company’s borrowings under its Credit Facility bear interest at an ABR or SOFR basis plus an applicable margin and the ABS loans have a fixed interest rate. At this time, the Company does not plan to enter into additional contracts using LIBOR as a reference rate. For additional information, see Note 9 – Debt.
In October 2021, the FASB issued ASU 2021-07, “Compensation – Stock Compensation (Topic 718): Determining the Current Price of an Underlying Share for Equity-Classified Share-Based Awards” as a practical expedient to allow a nonpublic entity to determine the current price input of equity-classified share-based awards issued to both employees and nonemployees using the reasonable application of a reasonable valuation method. The practical expedient describes the characteristics of the reasonable application of a reasonable valuation method as the same characteristics used in the regulations of the U.S. Department of Treasury for income tax purposes (the “Treasury Regulations”). Consequently, a reasonable valuation performed in accordance with the Treasury Regulations is an example of a way to achieve the practical expedient. This accounting standard had no effect on the Company and the company continues to use a reasonable valuation method for its equity classified awards.
In March 2023, the FASB issued an ASU to amend certain provisions of Accounting Standards Codification ("ASC”) Topic 842, “Leases” (“ASC 842”) that apply to arrangements between related parties under common control. The ASU amends the accounting for the amortization period of leasehold improvements in common-control leases for all entities and requires certain disclosures when the lease term is shorter than the useful life of the asset. This ASU is effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted. This accounting standard had no effect on the Company and the Company will continue to evaluate the standard in the future.
New Pronouncements Issued But Not Yet Adopted
In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around an entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.
Use of Estimates
The preparation of financial statements and related footnotes in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Our significant estimates include oil and natural gas reserves; cash flow estimates used in impairment testing of oil and natural gas properties and midstream assets; depreciation, depletion, amortization (“DD&A”) and accretion; asset retirement obligations (“ARO”); accrued revenue and related receivables; operating expenses and accrued liabilities; valuation of liability-classified incentive awards; mark-to-market valuations; and unit-based compensation. We believe our estimates are reasonable, and actual results could differ significantly from these estimates.
Cash and Restricted Cash
Our cash consists of cash in the bank. Current restricted cash represents funds held in escrow that will be used to settle certain general unsecured claims related to the 2018 bankruptcy and cash held in a liquidity reserve account, collection account, and plug and abandonment account maintained in connection with the ABS Financing Transaction. As of September 30, 2024, the amounts in Restricted Cash consisted of $3.2 million, $20.4 million, $12.1 million, and $0.9 million for the escrow, liquidity reserve, collection, and plug and abandonment accounts, respectively. As of December 31, 2023, the amounts in Restricted Cash consisted of $3.2 million $23.6 million, and $5.1 for the escrow, liquidity reserve, and collection accounts, respectively. As of September 30, 2024 and December 31, 2023, long-term restricted cash did not have a balance.
Revenue Recognition and Natural Gas Balancing
We recognize revenues from the sale of oil, natural gas and natural gas liquid (“NGL”) when control of the oil, natural gas and NGL production has transferred to the customer, the transaction price has been determined and collectability is reasonably assured and evidenced by a contract. Performance obligations under our contracts with customers are typically satisfied when oil, natural gas and NGL are transferred through delivery at the inlet of pipeline or processing plant, onloading to the delivery truck or barge.
Oil terminal revenues are recognized when delivery to the purchaser has occurred, title has transferred, and the associated receivable is recoverable.
We generate gathering revenues by providing gathering and compression services to third parties. We recognize revenue for these arrangements over time based on a per unit rate applied to volumes that travel through the gathering system. In addition, we retain any drip liquids collected on our gathering systems. The value of these drip liquids is recognized as part of gathering revenue in the month the underlying gathering service is provided based upon the price realized for sale of drip condensate to third party customers which represents a market price.
Natural gas production imbalances represent the fair value of amounts payable or receivable for natural gas production imbalances, and revenues are recognized based on our share of volumes sold, regardless of whether we have taken our proportional share of volume produced. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of September 30, 2024 and December 31, 2023, our natural gas production imbalance asset of $3.8 million and $3.1 million, respectively, was included in other long-term assets and natural gas production imbalance liability of $22.7 million and $21.8 million, respectively, was included in other long-term liabilities on our consolidated balance sheets.
Inventory
Inventory represents our share of crude oil produced from our Florida and Texas operations that is held in storage tanks and unsold at the end of the period. Inventory is reported as current assets in our consolidated balance sheets and carried at the lower of cost or market. We assess the carrying value of our inventory periodically to determine any adjustments necessary to reduce the carrying value to net realizable value. Uncertainties that may impact our assessment include: the applicable quality and location differentials and changes in the timing of a sale. We did not recognize any write-downs during the periods presented.
Property, Plant and Equipment
Proved Oil and Natural Gas Properties
We account for oil and natural gas exploration and development activities using the successful efforts method. Under this method, all property acquisition and development costs are capitalized when incurred and depleted on a unit-of-production basis over total proved reserves and proved developed reserves, respectively. Proved leasehold costs associated with proved reserves are depleted based on total proved reserves, which include proved undeveloped reserves.
Costs of retired, sold or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently in the consolidated statements of operations.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
Unproved Oil and Natural Gas Properties
Unproved oil and natural gas properties include lease acquisition costs which are costs incurred to acquire unproved leases. Lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. Lease acquisition costs that are expensed are recorded as “impairment of oil and natural gas properties” in our consolidated statements of operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as recovery of costs unless the proceeds exceed the entire cost of the property.
Impairment of Oil and Natural Gas Properties
We evaluate proved oil and natural gas properties for impairment whenever facts or circumstances indicate that the carrying values of such properties may not be recoverable. We perform impairment assessments by grouping assets at the lowest level for which there are identifiable cash flows. Impairment is indicated when a triggering event occurs and/or the sum of the estimated future net cash flows of an evaluated asset group is less than the asset group’s carrying value. Triggering events may include potential disposition of assets and declines in oil, natural gas and NGL prices. If impairment is indicated, we estimate fair value using a discounted cash flow approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with risk and current market conditions associated with realizing the expected cash flows projected.
We evaluate unproved oil and natural gas properties periodically for impairment on a geographic basis based on remaining lease terms, drilling results or future plans to develop acreage. These factors may be affected by economic factors including future oil and natural gas prices and projected capital costs.
We evaluate the recoverability of our other property, plant and equipment whenever events or circumstances indicate a decline in the recoverability of the respective carrying values may have occurred. We compare the net carrying value of the asset group to the undiscounted net cash flows projected. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount to fair value.
Impairment expense for proved and unproved properties is reported as “impairment of oil and natural gas properties” in the consolidated statements of operations. Impairment expense for other property, plant and equipment is reported as “impairment of long-lived assets” in the consolidated statements of operations.
Other Property, Plant and Equipment
Other property, plant and equipment include buildings, field equipment, compressors, furniture, leasehold improvements, computer hardware and software. We record other property, plant and equipment at cost and depreciate the assets using the straight-line method over the estimated lives of the individual assets.
We assign the useful lives of our property, plant and equipment based upon our internal estimates that are reviewed by management periodically. We use estimated lives of 20 years for our buildings, two to seven years for field equipment, furniture and computer hardware and software, and the remaining lease term for leasehold improvements. At the time of sale or disposal, the costs and accumulated DD&A of the sold or disposed assets are removed from our consolidated balance sheets with any gain or loss realized in our consolidated statements of operations.
Midstream Assets
Midstream assets consist primarily of natural gas gathering facilities and pipelines, as well as an oil terminal. Renewals and betterments, which substantially extend the useful lives of the assets, are capitalized and reported as other property, plant and equipment in our consolidated balance sheets. Maintenance and repairs are expensed when incurred. These assets are depreciated using the straight-line method over 3 to 30 years. We consider estimated future dismantlement, restoration and abandonment costs in our calculation of straight-line DD&A for our natural gas gathering, processing facilities and pipelines.
Leases
At inception, contracts are assessed for the presence of a lease according to the criteria prescribed by Accounting Standards Codification ("ASC”) Topic 842, “Leases” (“ASC 842”). If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the consolidated balance sheet as operating lease right-of-use assets with the corresponding lease liabilities presented as operating lease obligations - current and Operating lease obligations ‑ noncurrent. Finance lease assets are presented on the consolidated balance sheet as other property, plant and equipment with the corresponding liabilities presented in current portion of long-term debt and long-term debt.
Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. For leases where the implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.
Operating leases are expensed according to their nature and recognized in operating expenses or general and administrative expenses. Finance leases are depreciated and amortized with the relevant expenses recognized in depreciation, depletion and amortization and interest expense on the consolidated statement of operations.
Revenue and Production Taxes Payable
We calculate and pay taxes and royalties on crude oil and natural gas in accordance with particular contractual provisions of the leases, license or concession agreements and the laws and regulations applicable to those agreements.
Asset Retirement Obligations
We recognize estimated liabilities for future costs associated with the abandonment of our oil and natural gas properties, gas gathering, processing facilities and pipelines. We record a liability for the fair value of an ARO and a corresponding increase to the carrying value of the related long-lived asset in the period in which wells are drilled or acquired. See Note 10 – Asset Retirement Obligations for further discussion.
Liability-Classified Awards
We classify certain awards that will be settled in cash as liability awards in our consolidated balance sheets in accounts payable and accrued expenses. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense and operating costs over the vesting period of the award. The Company’s liability-classified awards include a performance condition based on preceding Implied Equity Value. See Note 5 – Financial Instruments and Fair Value Measurements for further discussion.
Unit-Based Compensation
Unit-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards is recognized on a straight-line basis over the requisite service period.
Environmental Liabilities
We are subject to federal, state and local environmental laws and regulations. These laws regulate the release, disposal or discharge of materials into the environment or otherwise relate to environmental protection. These laws and regulations may require that we remove or mitigate the environmental effect of the discharge, disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. We expense expenditures related to an existing condition caused by past operations that have no future economic benefit. We record liabilities for noncapital expenditures when environmental assessments or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability is fixed or determinable. We did not have environmental liabilities at September 30, 2024 and December 31, 2023, respectively.
Business Combinations and Asset Acquisitions
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition-date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of the proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average costs of capital rate are subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and natural gas properties within the same regions and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired in recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded as a bargain purchase gain in other income, net on our consolidated statements of operations.
In an asset acquisition, transaction costs are capitalized, and any excess or deficit of fair value of net assets in relation to acquisition price is allocated to the acquired assets based on the relative fair value.
Commitments and Contingencies
We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine that it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the mostly likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss.
Fair Value of Financial Instruments
Certain of our financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Our financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 – Financial Instruments and Fair Value Measurements for additional details.
Fair Value of Nonfinancial Assets and Liabilities
We apply fair value accounting guidance to measure our nonfinancial assets and liabilities such as those obtained through property, plant and equipment, AROs and restructuring. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production and other applicable sales estimates, operational costs and risk-adjusted discount rate. We may use the present value of estimated future cash inflows and outflows, third-party offers or prices of comparable assets with consideration of the current market conditions to value our nonfinancial assets and liabilities when circumstances dictate fair value determination is necessary.
Concentrations of Credit Risk
We are subject to credit risk resulting from the concentration of our oil, natural gas and NGL receivables with the following major purchasers that accounted for 10% or more of our total oil, natural gas and NGL sales for the periods presented:
| | | Nine Months Ended September 30, | |
| Purchaser | | 2024 | | | 2023 | |
| Customer A | | | 15 | % | | | 12 | % |
| Customer B | | | 13 | % | | | 6 | % |
| Customer C | | | 12 | % | | | 12 | % |
Our financial instruments with credit risk exposure consist principally of cash, accounts receivable, and derivative instruments. We maintain cash in deposit accounts at financial institutions that may exceed the federally insured limits. We monitor credit risk exposure by (i) placing our assets and other financial instruments with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include our evaluation of customers’ financial condition and monitoring payment history and (iii) netting derivative assets and liabilities where we have legal right of offset with counterparties and diversifying our derivative instrument portfolio.
Risk Management and Derivative Instruments
We have entered into derivative contracts with counterparties to reduce the effect of changes in oil and natural gas prices on a portion of our oil and natural gas production. We do not enter into such contracts for speculative trading purposes. Our commodity derivative instruments are measured at fair value in our consolidated balance sheets as derivative assets or derivative liabilities. We have not designated any derivative instruments as hedges for accounting purposes. Gains and losses from valuation changes in commodity derivatives are reported as (gain) loss on commodity derivative instruments in our consolidated statements of operations. Our cash flows are only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. Cash settlements are reflected as operating activities in our consolidated statements of cash flows. We expense transaction costs related to the modification of derivative instruments as incurred. See Note 5 – Financial Instruments and Fair Value Measurements for further discussion of our derivative instruments.
We have market and credit risk exposure due to commodity derivatives that are concentrated with certain counterparties who are affiliate lenders under the Credit Agreement. We believe the risk of nonperformance by our counterparties is low as we execute our derivative contracts only with credit-worthy financial institutions and we have no past-due receivables from our derivative counterparties. As of September 30, 2024, J. ARON & Company, JP Morgan Chase Bank N.A., and KeyBank, which accounted for approximately 60%, 39%, and 1%, respectively, of our total hedge settlement receivable.
Our commodity derivative contracts are documented with industry standard contracts known as Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the oil and natural gas properties securing the Credit Agreement. We have certain limitations under the Credit Agreement, including a provision that limits the total amount of our production that may be hedged to certain percentages of current and forecasted production. As of September 30, 2024, we were in compliance with these limitations. See Note 5 – Financial Instruments and Fair Value Measurements and Note 9 – Debt for additional information.
Debt Issuance Costs
Debt issuance costs related to our Credit Facility and ABS Notes are amortized over the life of the related debt using the effective interest rate method and unamortized debt issuance costs are netted against the outstanding balance of debt obligations on our consolidated balance sheets. Any unamortized costs associated with retired debt are written off and included in the determination of gain or loss on extinguishment of debt.
Revenues
Sales of oil, natural gas and NGL are recognized at the point when control of the commodity is transferred to the customer and collectability is reasonably assured. Most of our contracts’ pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with the other available oil, natural gas and NGL suppliers.
Oil Sales
Under our crude purchase and marketing contracts, we generally sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. We recognize revenue when control transfers to the purchaser at the wellhead or delivery point for onloading to delivery truck or barge at the net price received.
Natural Gas and NGL Sales
Under our natural gas gathering, processing and purchase contracts, we deliver unprocessed natural gas to processing plants at the wellhead or the inlet of the processing plant’s system. The midstream entity then gathers and processes the natural gas to produce residue gas and NGLs generated from processing. In the majority of cases, the midstream entity remits payment to us for NGLs based on index-based pricing or weighted average sales proceeds less deductions which may include gathering, processing and transportation fees, while the residue gas is redelivered to us at the tailgate of the midstream entity’s processing plant for marketing under separate contracts. We sell residue gas at the delivery point specified in the separate contract and collect an agreed-upon index price, net of pricing differentials. Transportation, gathering and processing costs incurred after control transfers to the purchaser are recognized as reductions to revenues rather than as operating costs.
Oil Terminal Sales
Under our oil terminal sales contracts, we sell oil at the delivery point specified in the contract and collect an agreed-upon index price, net of pricing differentials. Control as defined under ASC 606, “Revenue from Contracts with Customers” (“ASC 606”) passes at the delivery point. The delivery point is the point at which the oil passes the last permanent delivery flange or meter connecting our facility to customer’s facility. At the delivery point, the customer takes physical custody, title and risk of loss of the product and we have a right to receive payment for the sale. We recognize revenue at the net price received when control transfers to the customer. Oil terminal sales are reported in other revenues, net on our consolidated statements of operations.
Gathering Revenue
We generate gathering revenues by providing gathering and compression services to third parties, which are reported in other revenues, net on our consolidated statement of operations. We recognize revenue for these arrangements over time based on a per unit rate applied to volumes that travel through the gathering system. In addition, we retain any drip liquids collected on our gathering systems. The value of these drip liquids is recognized as part of gathering revenue in the month the underlying gathering service is provided based upon the price realized for sale of drip condensate to third party customers which represents a market price.
Purchased Condensate Sales
The Company’s purchased oil and natural gas sales are derived from the sale of oil and natural gas purchased from a third party and reported in other revenues, net on our consolidated statements of operations. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased oil or natural gas before it is transferred to the customer.
Performance Obligations
A significant number of our product sales are short-term in nature with a contract term of one year or less. We record revenue on our oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the production is delivered.
We have elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue under the right to invoice practical expedient.
Contract Balances
We invoice our customers when we have satisfied our performance obligations, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.
Accounts Receivable and Allowance for Credit Losses
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to third party purchasers. Accounts receivable is held at cost. At each reporting date, the Company assesses the expected lifetime credit losses on initial recognition of accounts receivable. At September 30, 2024, the credit loss allowance on accounts receivable was $5.8 million, and no credit losses were recorded during the nine months ended September 30, 2024. At December, 2023, the credit loss allowance on accounts receivable from joint interest owners was $5.8 million, and no credit losses were recorded during the nine months ended September 30, 2023.
| 3. | Supplemental Cash Flow Information |
Supplemental disclosures to the consolidated statements of cash flows are presented below:
| | | Nine Months Ended September 30, | |
| in thousands of dollars | | 2024 | | | 2023 | |
| Cash payments | | | | | | |
| Interest | | $ | 64,337 | | | $ | 33,606 | |
| Taxes | | | 161 | | | | 7 | |
| Noncash investing activities | | | | | | | | |
| (Increase) decrease in accrued capital expenditures | | $ | 12,228 | | | $ | (1,413 | ) |
| (Increase) decrease in asset retirement obligations | | | (2,986 | ) | | | (10,990 | ) |
| (Increase) decrease in assets under operating leases | | | - | | | | (10,939 | ) |
| (Increase) decrease in liabilities for asset divestitures | | | (628 | ) | | | 3,580 | |
| Noncash financing activities | | | | | | | | |
| (Increase) decrease in assets under finance leases | | | (35 | ) | | | (1,753 | ) |
| Reconciliation of cash and restricted | | | | | | | | |
| cash reported in the consolidated balance sheets | | | | | | | | |
| Cash | | $ | 40,137 | | | $ | 10 | |
| Restricted cash | | | 36,736 | | | | 3,232 | |
| Total cash and restricted cash | | | | | | | | |
| shown in the statement of cash flows | | $ | 76,873 | | | $ | 3,242 | |
| 4. | Acquisitions, Divestitures, and Assets Held for Sale |
Acquisitions
During the nine months ended September 30, 2024 and 2023, the Company did not have any material acquisitions.
Transactions Between Subsidiaries of the Company
On October 26, 2023, Unbridled entered into an asset purchase agreement with ABS Issuer (the “Purchase and Sale Agreement”). Unbridled agreed to sell and transfer to ABS Issuer certain operated and non-operated oil and natural gas wells and all oil and natural gas leases, subleases and leasehold covering such wells (the “ABS Assets” and such transfer, the “ABS Asset Transfer”) for a purchase price of $640 million, of which $630 million was cash and $10 million was a non-cash note payable, which was subsequently issued to a third party in January 2024 for $10 million in cash and accrued interest of $0.2 million.
In connection with the transaction, ABS Issuer entered into an indenture with UMB Bank, N.A. as indenture trustee (the “Indenture Trustee”) (the “Indenture”) to which ABS Issuer issued (a) $640 million aggregate principal amount of Series 2023-1 Notes, consisting of (i) $285 million aggregate principal amount of its 8.121% Series 2023-1 Notes, Class A-1 Notes due December 2038, (ii) $260 million aggregate principal amount of its 8.946% Series 2023-1 Notes, Class A-2 Notes due December 2038 and (iii) $95 million aggregate principal amount of its 12.436% Series 2023-1 Notes, Class B Notes due December 2038 (collectively, the “ABS Notes”) and (b) pledged the ABS Assets to the Indenture Trustee to secure the ABS Issuer’s obligations under the Indenture (the “ABS Financing Transaction”).
In addition the following events occurred in connection with the transaction: (i) $10 million of the ABS Notes were issued to Maverick, (ii) a holdback of $5.4 million related to consents not received at the date of the transaction which is reflected as restricted cash, (iii) a Liquidity Reserve Account was established for $23.6 million and is reflected as restricted cash, (iv) $260 million was an equity distribution and (v) repaid $300 million for the Credit Facility.
We incurred hedge novation fees of $4.6 million in conjunction with the ABS Financing Transaction which were expensed as incurred in general and administrative expenses in our consolidated statement of operations. We incurred $12.7 million of costs including legal fees and administrative fees in connection with the ABS Financing Transaction which were capitalized as deferred financing costs and recorded as an offset to the carrying value of the ABS Notes.
Divestitures
In May 2024, we entered into an agreement with a third party to divest certain properties in west Texas. The divestiture was executed without a purchase price, and the Company received no financial consideration for the transaction. We recognized a $2.2 million gain on the sale for the nine months ended September 30, 2024.
The gain was primarily due to relief of related asset retirement obligations.
In March 2023, we entered into an agreement with a third party to divest certain interests in oil and natural gas properties, rights and related assets in Western Anadarko Basin for a purchase price of $10.0 million. This sale was accounted for as a normal retirement under the provisions of paragraph ASC 932-360-40-3 with no gain or loss recorded on the sale for the nine months ended September 30, 2023.
In May 2023, we entered into an agreement with a third party to divest certain properties in west Texas for a purchase price of $4.5 million. We recognized a $0.3 million gain on the sale for the nine months ended September 30, 2023.
Assets Held for Sale
In August 2024, the Company entered into two agreements with two separate third parties to sell certain East Texas assets (the “East Texas Sale”) for a combined purchase price totaling $97.0 million. As of September 30, 2024, the held for sale criteria were met. The related oil and natural gas properties, other property and equipment, asset retirement obligations, and revenue in suspense are classified as held for sale and presented separately in the appropriate asset and liability sections of the consolidated balance sheet. The transactions closed in October 2024.
| 5. | Financial Instruments and Fair Value Measurements |
Commodity Activities
At September 30, 2024, our commodity derivatives consisted of fixed price swaps and two-way costless collars. Our fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor). The two-way collars are a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling). For both swaps and collars, all transactions are settled in cash for the net difference between settlement and contract prices, multiplied by the hedged contract volumes, for the settlement period.
Our commodity derivative contracts settle monthly based on the differential between the contract price and the average NYMEX West Texas Intermediate index price (“NYMEX WTI”) (oil), average NYMEX Henry Hub index price (“NYMEX HH”) (natural gas) and Mont Belvieu Oil Price Information Service (“OPIS”) (NGLs). The following table presents derivative positions for the periods indicated as of September 30, 2024:
| | | 2024 | | | 2025 | | | 2026 | | | 2027 | | | 2028 | | | 2029 | | | 2030 | |
| Oil Positions | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Fixed Price Swaps - NYMEX WTI | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 13,450 | | | | 11,926 | | | | 10,623 | | | | 3,688 | | | | 3,366 | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 71.88 | | | $ | 71.85 | | | $ | 68.45 | | | $ | 65.95 | | | $ | 62.21 | | | $ | - | | | $ | - | |
| Costless Collar - NYMEX WTI | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 1,000 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Average Put Price ($/Bbl) | | $ | 67.00 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Average Call Price ($/Bbl) | | $ | 80.35 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 14,450 | | | | 11,926 | | | | 10,623 | | | | 3,688 | | | | 3,366 | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 72.01 | | | $ | 71.85 | | | $ | 68.45 | | | $ | 65.95 | | | $ | 62.21 | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Price Swaps - Henry Hub | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (MMBtu/d) | | | 106,285 | | | | 108,838 | | | | 86,514 | | | | 69,070 | | | | 61,056 | | | | 50,962 | | | | 47,714 | |
| Average Price ($/MMBtu) | | $ | 3.49 | | | $ | 3.89 | | | $ | 3.87 | | | $ | 3.76 | | | $ | 3.63 | | | $ | 3.41 | | | $ | 3.27 | |
| Costless Collar - Henry Hub | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 10,000 | | | | - | | | | 10,000 | | | | - | | | | - | | | | - | | | | - | |
| Average Put Price ($/Bbl) | | $ | 2.50 | | | $ | - | | | $ | 3.50 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Average Call Price ($/Bbl) | | $ | 5.80 | | | $ | - | | | $ | 5.15 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (MMBtu/d) | | | 116,285 | | | | 108,838 | | | | 96,514 | | | | 69,070 | | | | 61,056 | | | | 50,962 | | | | 47,714 | |
| Average Price ($/MMBtu) | | $ | 3.54 | | | $ | 3.89 | | | $ | 3.87 | | | $ | 3.76 | | | $ | 3.63 | | | $ | 3.41 | | | $ | 3.27 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| NGL Positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Price Swaps | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 10,500 | | | | 8,661 | | | | 6,127 | | | | - | | | | - | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 0.91 | | | $ | 0.88 | | | $ | 0.83 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 10,500 | | | | 8,661 | | | | 6,127 | | | | - | | | | - | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 0.91 | | | $ | 0.88 | | | $ | 0.83 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Gas Basis Swap | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 90,219 | | | | 84,068 | | | | 77,423 | | | | - | | | | - | | | | - | | | | - | |
| Average Price ($/MMBtu) | | $ | (0.19 | ) | | $ | (0.26 | ) | | $ | (0.23 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Balance Sheet Presentation
The following table summarizes the fair value of the derivatives outstanding on a gross and net basis:
| | September 30, 2024 | |
| | | Oil | | | Natural Gas | | | NGL | | | Commodity | | | Total | |
| | | Commodity | | | Commodity | | | Commodity | | | Derivatives | | | Financial | |
| Financial Statement Caption, thousands of dollars | | Derivatives | | | Derivatives | | | Derivatives | | | Netting (a) | | | Instruments | |
| Assets | | | | | | | | | | | | | | | |
| Current assets - derivative instruments | | $ | 21,632 | | | $ | 28,369 | | | $ | 10,634 | | | $ | (23,054 | ) | | $ | 37,581 | |
| Other long-term assets - derivative instruments | | $ | 13,825 | | | $ | 32,174 | | | $ | 8,968 | | | $ | (31,816 | ) | | | 23,151 | |
| Total assets | | | 35,457 | | | | 60,543 | | | | 19,602 | | | | (54,870 | ) | | | 60,732 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | |
| Current liabilities - derivative instruments | | $ | (23 | ) | | $ | (4,162 | ) | | $ | (18,869 | ) | | $ | 23,054 | | | | - | |
| Long-term liabilities - derivative instruments | | $ | (2,457 | ) | | $ | (17,085 | ) | | $ | (12,822 | ) | | $ | 31,816 | | | | (548 | ) |
| Total liabilities | | | (2,480 | ) | | | (21,247 | ) | | | (31,691 | ) | | | 54,870 | | | | (548 | ) |
| Net assets | | $ | 32,977 | | | $ | 39,296 | | | $ | (12,089 | ) | | $ | - | | | $ | 60,184 | |
| | | December 31, 2023 | |
| | | Oil | | | Natural Gas | | | NGL | | | Commodity | | | Total | |
| | | Commodity | | | Commodity | | | Commodity | | | Derivatives | | | Financial | |
| Financial Statement Caption, thousands of dollars | | Derivatives | | | Derivatives | | | Derivatives | | | Netting (a) | | | Instruments | |
| Assets | | | | | | | | | | | | | | | |
| Current assets - derivative instruments | | $ | 7,539 | | | $ | 39,124 | | | $ | 18,958 | | | $ | (19,118 | ) | | $ | 46,503 | |
| Other long-term assets - derivative instruments | | | 30,451 | | | | 39,797 | | | | 23,687 | | | | (45,917 | ) | | | 48,018 | |
| Total assets | | | 37,990 | | | | 78,921 | | | | 42,645 | | | | (65,035 | ) | | | 94,521 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | |
| Current liabilities - derivative instruments | | | (2,897 | ) | | | (1,931 | ) | | | (14,388 | ) | | | 19,118 | | | $ | (98 | ) |
| Long-term liabilities - derivative instruments | | | (24 | ) | | | (29,262 | ) | | | (20,625 | ) | | | 45,917 | | | | (3,994 | ) |
| Total liabilities | | | (2,921 | ) | | | (31,193 | ) | | | (35,013 | ) | | | 65,035 | | | | (4,092 | ) |
| Net liabilities | | $ | 35,069 | | | $ | 47,728 | | | $ | 7,632 | | | $ | - | | | $ | 90,429 | |
| (a) | Represents counterparty netting under our ISDA Agreements. See Note 2 – Summary of Significant Accounting Policies. For our derivative contracts, we may enter into master netting, collateral and offset agreements with counterparties. These agreements provide us the ability to offset a counterparty’s rights and obligations, request additional collateral when necessary, or liquidate the collateral in the event of counterparty default. We net the fair value of cash collateral paid or received against fair value amounts recognized for net derivative positions executed with the same counterparty under the same master netting or offset agreement. |
The following table summarizes the unrealized gains/losses on commodity derivatives, which are included in the “loss on commodity derivative instruments” line of the consolidated income statement:
| | | Oil | | | Natural Gas | | | NGL | | | Total | |
| | | Commodity | | | Commodity | | | Commodity | | | Financial | |
| in thousands of dollars | | Derivatives | | | Derivatives | | | Derivatives | | | Instruments | |
| Nine Months Ended September 30, 2024 | | | (2,092 | ) | | | (8,433 | ) | | | (19,721 | ) | | | (30,246 | ) |
| Nine Months Ended September 30, 2023 | | | (38,207 | ) | | | 37,977 | | | | 7,708 | | | | 7,478 | |
The following table summarizes the realized gains/losses on commodity derivatives, which are included in the “loss on commodity derivative instruments” line of the consolidated income statement:
| | Oil | | | Natural Gas | | | NGL | | | Total | |
| | | Commodity | | | Commodity | | | Commodity | | | Financial | |
| in thousands of dollars | | Derivatives | | | Derivatives | | | Derivatives | | | Instruments | |
| Nine Months Ended September 30, 2024 | | | (15,214 | ) | | | 53,333 | | | | (10,196 | ) | | | 27,923 | |
| Nine Months Ended September 30, 2023 | | | (25,832 | ) | | | 5,620 | | | | (14,608 | ) | | | (34,820 | ) |
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We measure certain assets and liabilities at fair value, using the fair value hierarchy noted below. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third-party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows:
| Level 1 | Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. |
| Level 2 | Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter (“OTC”) commodity derivative contracts in our portfolio to be Level 2. |
| Level 3 | Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. We consider our liability-classified long term incentive plan awards and put option liability to be Level 3 liabilities. See Note 12 – Equity for additional details. |
Our assessment of the significance of an input to its fair value measurement requires judgment and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.
Commodity Derivative Instruments
Our commodity derivative instruments include oil, natural gas and NGL swaps and collars. The fair value of our commodity derivative instruments is based on upon a third-party preparer’s calculation using mark-to-market valuation reports provided by our counterparties for monthly settlement purposes to determine the valuation of our derivative instruments. We do not have access to the specific proprietary valuation models or inputs used by our counterparties or third-party preparer.
We compare the third-party preparer’s valuation to counterparty valuation statements and investigate any significant differences. Additionally, we analyze monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The fair values reflect nonperformance risk inherent in the transaction using current credit default swap values for each counterparty for asset positions and the Company’s creditworthiness for liability positions. Accordingly, we recorded an adjustment to the fair value of our net derivative liability of $2.7 million and $4.5 million at September 30, 2024 and December 31, 2023, respectively.
Fair Value – Recurring Measurement Basis
The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis on our consolidated balance sheets at September 30, 2024 and December 31, 2023 by level within the fair value hierarchy.
| | | September 30, 2024 | |
| in thousands of dollars | | Level 1 | | Level 2 | | Level 3 | | Total | |
Commodity derivative instruments (1) | | | | | | | | | | |
| Assets | | | | | 115,603 | | | | | | 115,603 | |
| Liabilities | | | | | (55,419 | ) | | | | | (55,419 | ) |
| Net assets (liabilities) | $ | - | | $ | 60,184 |
| $
| - | | $ | 60,184 | |
| | December 31, 2023 | | | | | | |
| in thousands of dollars | | Level 1 | | Level 2 | | Level 3 | | Total | |
Commodity derivative instruments (1) | | | | | | | | | | |
| Assets | | | | | 159,557 | | | | | | 159,557 | |
| Liabilities | | | | | (69,127 | ) | |
| | | (69,127 | ) |
| Net assets (liabilities) | $
| - | | $ | 90,430 | | $
| - | | $ | 90,430 | |
| (1) | The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances. |
Fair Value – Nonrecurring Measurement Basis
Acquisitions and impairment of proved and unproved properties and other non-oil and natural gas properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of property as of the measurement date which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil and condensate, natural gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company’s historic experience with similar properties. These inputs are not observable in the market and represent level 3 inputs. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.
| 6. | Long-Lived Assets and Impairment |
Our long-lived assets are comprised of oil and natural gas properties and other property, plant and equipment for the periods presented:
| in thousands of dollars | | September 30, 2024 | | | December 31, 2023 | |
Proved oil and natural gas properties(a) | | $ | 2,293,998 | | | $ | 2,548,263 | |
| Unproved oil and natural gas properties | | | 97,403 | | | | 126,557 | |
| Total oil and natural gas properties | | | 2,391,401 | | | | 2,674,820 | |
| Other property, plant and equipment | | | 119,920 | | | | 110,888 | |
| Less: Accumulated depletion, depreciation and amortization | | | (1,047,475 | ) | | | (1,097,788 | ) |
| Net property, plant and equipment | | $ | 1,463,846 | | | $ | 1,687,920 | |
| (a) | Estimates of future asset retirement costs of $263.4 million and $260.4 million are included in our proved oil and natural gas properties at September 30, 2024 and December 31, 2023, respectively. |
Costs are excluded from the amortization base until proved reserves are established or impairment is determined.
Long-Lived Assets Impairment
During the nine months ended September 30, 2024, we recorded impairment losses of $110.9 million on certain East Texas based assets detailed in Note 4 after entering into purchase and sale agreements for total consideration lower than the net book value of the asset group. During the nine months ended September 30, 2023, we recorded impairment losses of $62.7 million due to a significant decrease in commodity prices driven by a decrease in gas futures.
Other long-term assets consist of the following:
| in thousands of dollars | | September 30, 2024 | | | December 31, 2023 | |
| | | | | | | |
| Property reclamation | | $ | 12,381 | | | $ | 11,910 | |
| Unamortized debt issuance costs | |
| 9,078 | | |
| 13,206 | |
| Security deposits | |
| 1,458 | | |
| 1,735 | |
| Other | |
| 10,343 | | |
| 8,726 | |
| Total other long-term assets | | $ | 33,260 | | | $ | 35,577 | |
Net Profit Interest
As of December 31, 2023, we held a 50% net profit interest (“NPI”) related to Jay Field. The NPI is held 50% by Maverick and a third party (“NPI Holder”). Under the arrangement, the NPI is payable after: (i) funds are withheld, to the extent allowable each month under the arrangement, to pay for the NPI holder’s share of future development costs and abandonment obligations, and (ii) we are reimbursed for the NPI holder’s share of excess historical production costs.
Once the NPI holder’s share of the excess historical costs is reimbursed, the NPI will be payable monthly to the extent the NPI for that month exceeds the amount withheld for that month for future development costs and abandonment obligations.
In March 2024, the Company settled outstanding litigation related to the Jay NPI for $9.2 million, including $5.0 million to purchase the remaining 50% interest in the Jay NPI, and $4.2 million to settle all outstanding legal claims.
Property Reclamation Deposit
As of September 30, 2024 and December 31, 2023, we had a property reclamation deposit of $12.4 and $11.9 million, respectively, included in other long-term assets, held in an escrow account as security for future abandonment and remediation obligations for the Jay Field. We are required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to us until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, we have the right to request a refund of a portion or all of the property reclamation deposit. The seller has the sole discretion to grant our refund request. In addition to the cash deposit, we are required to provide letters of credit. At September 30, 2024 and December 31, 2023, we had $21.0 million in letters of credit related to the property reclamation deposit.
| 8. | Accounts Payable and Accrued Expenses |
Accounts payable and accrued expenses consist of the following:
| in thousands of dollars | | September 30, 2024 | | | December 31, 2023 | |
| Accounts payable | | $ | 105,687 | | | $ | 112,218 | |
| Revenue and royalties payable | | | 68,599 | | | | 93,315 | |
| Wages and salaries payable | | | 14,642 | | | | 21,008 | |
| Accrued interest payable | | | 4,906 | | | | 12,100 | |
| Production and property taxes payable | | | 19,252 | | | | 22,217 | |
| Hedge settlement payables | | | 4,820 | | | | 8,911 | |
| Other current liabilities | | | 2,933 | | | | 2,868 | |
| Total accounts payable and accrued expenses | | $ | 220,839 | | | $ | 272,637 | |
Our debt was comprised of the following:
| in thousands of dollars | | September 30, 2024 | | | December 31, 2023 | |
| Credit Facility | | $ | 224,000 | | | $ | 190,000 | |
| ABS Notes | | | 551,536 | | | | 640,000 | |
| Finance Lease Obligations | | | 2,706 | | | | 3,555 | |
| Debt issuance costs | | | (10,696 | ) | | | (12,377 | ) |
| Notes held by ABS parent | | | - | | | | (10,000 | ) |
| Total debt | | | 767,546 | | | | 811,178 | |
| Current portion, long-term debt | | | (108,965 | ) | | | (112,607 | ) |
| Current portion of finance lease obligations | | | (1,289 | ) | | | (1,166 | ) |
| Total long-term debt | | $ | 657,292 | | | $ | 697,405 | |
ABS Notes
In connection with the ABS Financing Transaction (see Note 4 – Acquisitions, Divestitures, and Assets Held for Sale), on October 26, 2023, ABS Issuer acquired certain oil and natural gas interests in currently-producing oil and natural gas wells and other assets from Unbridled pursuant to an asset purchase agreement and the acquisition was funded by the issuance of the ABS Notes (as defined in Note 4 – Acquisitions, Divestitures, and Assets Held for Sale), due December 2038, pursuant to a note purchase agreement. At September 30, 2024 and December 31, 2023, the ABS Notes were comprised of the following:
| in thousands of dollars | | September 30, 2024 | | | December 31, 2023 | |
| Series 2023 - 1 Class A-1 8.121% Notes | | $ | 232,597 | | | $ | 285,000 | |
| Series 2023 - 1 Class A-2 8.946% Notes | | | 239,166 | | | | 260,000 | |
| Series 2023 - 1 Class B 12.436% Notes | | | 79,773 | | | | 95,000 | |
| Total ABS Notes | | | 551,536 | | | | 640,000 | |
The ABS Notes are secured by certain oil and natural gas interests in currently producing oil and natural gas wells and other assets. The ABS Notes accrue interest at the respective stated per annum rates and have a final maturity date of December 15, 2038. Interest and principal payments are payable on a monthly basis. During the nine months ended September 30, 2024, we incurred $41.1 million of interest related to the ABS Notes.
The ABS Notes are subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the ABS Notes, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified make-whole payments under certain circumstances, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral are used in stated ways defective or ineffective, (iv) covenants related to recordkeeping, access to information and similar matters, and (v) the Issuer will comply with all laws and regulations which it is subject to. The ABS Notes are also subject to customary accelerated amortization events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, failure to maintain certain production metrics, certain change of control and management termination events, and event of default and the failure to repay or refinance the ABS Notes on the applicable scheduled maturity date. The ABS Notes are subject to certain customary events of default, including events relating to non-payment of required interest, principal, or other amounts due on or with respect to the ABS Notes, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.
Under the indenture, the Company must maintain the following financial covenants determined as of the last day of the quarter: 1) Aggregate Debt Service Coverage Ratio (DSCR) of at least 1.05, 2) Senior DSCR of at least 1.25, 3) Senior IO DSCR of at least 1.20.
As of September 30, 2024, we were in compliance with our covenants under the ABS Notes.
Senior Secured Reserve-Based Credit Facility
On January 27, 2022, we entered into an agreement with a syndicate of banks including JPMorgan Chase Bank acting as Administrator, Royal Bank of Canada, Citizens Bank, KeyBank National Association acting as co‑syndication agents, RBC Capital Markets, and KeyBank Capital Markets (the “Credit Facility”). The agreement is for a maximum $1 billion credit facility with an initial $500 million borrowing base. The maturity date is April 1, 2026. The Credit Facility replaced the Credit Agreement (defined below) subsequent to its closing on April 1, 2022, incurring deferred financing costs of $16.3 million.
The Credit Facility limits the amounts we could borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. Our obligations under the credit facility were collateralized by substantially all of our oil and natural gas properties, including mortgage liens on oil and natural gas properties having at least 85% of the reserve value as determined by reserve reports.
The Credit Facility contains certain customary affirmative and negative covenants, including financial covenants requiring maintenance of the Consolidated Total Debt to EBITDAX Ratio to be less than 3.00 to 1.00 and a Current Ratio of no less than 1.00 to 1.00.
At our election, borrowings under the credit facility may be made on an Alternate Base Rate (“ABR”) or a Secured Overnight Financing Rate (“SOFR”) basis plus an applicable margin. In connection with the Credit Facility, the applicable margins vary from 2.00% to 3.00% for ABR borrowings and 3.00% to 4.00% for SOFR borrowings depending on the borrowing base. In addition, we are also required to pay a commitment fee on the amount of any unused commitments at a rate of 0.50% per annum. Interest on ABR borrowings and the commitment fee are generally payable quarterly. As of September 30, 2024, the effective interest rate of the Credit Facility was 8.87%.
In June 2022, we entered into an amendment to the Credit Facility (the “First Amendment”) which increased the borrowing base from the initial $500 million to $750 million. Each lender’s borrowing capacity was increased with the exception of Goldman Sachs Bank, and we accounted for the First Amendment as a modification of debt. We incurred deferred financing costs of $2.6 million in relation to this amendment.
In October 2022, we entered into the second amendment to the Credit Facility (the “Second Amendment”), which increased the borrowing base to $1 billion. Each lender’s borrowing capacity was increased with the exception of Texas Capital Bank, and we accounted for the Second Amendment as a modification of debt. We incurred deferred financing costs of $2.6 million in relation to this amendment.
In July 2023, we entered into the third amendment to the Credit Facility (the “Third Amendment”), which reduced the borrowing base from $1 billion to $750 million. Each lender’s borrowing capacity was decreased, and we accounted for the Third Amendment as a modification of debt. Additionally, the Third Amendment allowed for a one-time cash distribution to our equity holders not to exceed $10 million in aggregate through September 30, 2023. We did not incur deferred financing costs in relation to the Third Amendment.
In October 2023 in conjunction with the ABS Financing Transaction, we entered into the fourth amendment to the Credit Facility (the “Fourth Amendment”), which amended in its entirety the original Credit Facility. Pursuant to the Fourth Amendment, among other things, the borrowing base was reduced from $750 million to $350 million, and the respective reduced commitments of the various lending banks were reallocated among the continuing lenders to assign the exiting lenders’ commitment. We accounted for the decreases in a lender’s borrowing capacity as a modification and accounted for any lender that exited the credit facility as a debt extinguishment. In connection with the ABS financing transaction, we repaid $0.0 million as of December 31, 2023. We incurred deferred financing costs of $5.6 million in relation to the Fourth Amendment.
In September 2024, we entered into the fifth amendment to the Credit Facility (the “Fifth Amendment”), which, upon the close of the aforementioned East Texas Sale, reduced the borrowing base from $350 million to $315 million. Each lender’s borrowing capacity was decreased, and we accounted for the Fifth Amendment as a modification of debt, resulting in a $1.5 million write off of deferred financing costs to interest expense. Additionally, the Fifth Amendment allowed for distribution of stock proceeds from the East Texas Sale. At September 30, 2024, our borrowing base is $315.0 million, and the aggregate commitment of all lenders is $1 billion. Our next borrowing base redetermination is scheduled for May 1, 2025.
Unamortized debt issuance costs associated with the Credit Facility were $9.1 million as of September 30, 2024. The unamortized debt issuance costs are included in other long-term assets.
As of September 30, 2024, we were in compliance with our debt covenants under the Credit Facility.
Interest Expense
Our interest expense is as follows:
| | Nine Months Ended September 30, | |
| in thousands of dollars | | 2024 | | | 2023 | |
Credit Facility (a) | | $ | 17,624 | | | $ | 33,972 | |
| ABS Notes | | | 41,075 | | | | - | |
| Amortization of deferred debt issuance costs, Credit Facility | | | 2,875 | | | | 7,704 | |
| Amortization of deferred debt issuance costs, ABS Notes | | | 1,748 | | | | - | |
| Other Credit Facility, net | | | 237 | | | | 134 | |
| | | $ | 63,559 | | | $ | 41,810 | |
(a) Includes commitment fees and other fees | | $ | 646 | | | $ | 2,331 | |
| 10. | Asset Retirement Obligations |
We recognize the fair value of a liability for an ARO in the period it is incurred if a reasonable estimate of fair value can be made. Our ARO represents the present value of the expected costs to plug, abandon and remediate producing and shut-in wells at the end of the productive lives in compliance with applicable local, state and federal laws and applicable lease terms. We estimate the value of our ARO by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The ARO liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and natural gas properties using the unit-of-production method. We review our ARO estimates and assumptions periodically and, to the extent future revisions to these assumptions impact the fair value of the existing ARO liability, we make a corresponding adjustment to the related asset. We consider these inputs to be Level 3 inputs as discussed in Note 2 – Summary of Significant Accounting Policies and Note 5 – Financial Instruments and Fair Value Measurements.
The following table presents the balance and activity in our ARO for the periods presented:
| in thousands of dollars | | September 30, 2024 | | | December 31, 2023 | |
| Asset retirement obligations, beginning of period | | $ | 249,673 | | | $ | 253,281 | |
| Liabilities settled | | | (9,977 | ) | | | (19,839 | ) |
Liabilities related to divested properties(a) | | | (2,425 | ) | | | (9,970 | ) |
Liabilities related to held for sale properties(a) | | | (16,957 | ) | | | - | |
Revisions of estimates(b) | | | 2,985 | | | | 11,535 | |
Accretion expense(c) | | | 10,231 | | | | 14,666 | |
| Asset retirement obligations end of period | | | 233,530 | | | | 249,673 | |
| Less: Current portion of asset retirement obligations | | | (7,282 | ) | | | (7,282 | ) |
| Noncurrent portion of asset retirement obligations | | $ | 226,248 | | | $ | 242,391 | |
| (a) | Includes ARO related to various sold or held for sale properties. See Note 4 – Acquisitions, Divestitures, and Assets Held for Sale. |
| (b) | During the periods presented, we revised our estimates primarily to reflect the following changes in estimated well lives, oil and natural gas prices and plugging and abandonment cost estimates. |
| (c) | Included in DD&A on our consolidated statements of operations. |
| 11. | Commitments and Contingencies |
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily relate to abandonments, environmental and other responsibilities where governmental and other organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At both September 30, 2024 and December 31, 2023, we had $21.3 million of irrevocable letters of credit outstanding, of which $21.0 million related to the property reclamation deposit as discussed in Note 7 – Other Long-Term Assets. At September 30, 2024, no amounts were drawn under the letters of credit.
Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.
Common Units
During the nine months ended September 30, 2024, we repurchased 1,102 units for $1.1 million related to a certain terminated executive. As a result of recent executive terminations, the Company determined that there is an established history cash settling equity awards, which indicates that the substantive terms of the outstanding equity awards include a cash settlement feature, which results in a liability classification. The Company determined it appropriate to modify all outstanding equity awards to liability awards. This modification resulted in the reclassification from equity to liability awards of 8,960 units for $4.7 million. During the year ended December 31, 2023, we repurchased 3,222 units for $1.5 million for certain members and executives.
Member Distributions
There was a $0.2 million distribution in May 2024 related to a certain terminated executive. In September 2024, the Board approved a distribution of $24 million at $8.30 per common unit to the common unit holders on record on the applicable record date. In January 2023, the Board approved a distribution of $30 million at $10.36 per common unit to the common unitholders of record on the applicable record date. In May 2023, the Board approved two distributions totaling $50 million. The first distribution was $30 million at $10.36 per common unit to the common unitholders of record on the applicable record date. The second distribution was $20 million at $6.91 per common unit to the common unitholders of record on the applicable record date.
The state of Oklahoma requires operators to withhold 5% of all production revenues associated with royalty interests held by Oklahoma nonresidents to be offset against state income taxes. As Maverick is not subject to income taxes as a limited liability company, the tax liability associated with the operations of Unbridled is the responsibility of the members. As such, the balance of Oklahoma state withholding has been reflected as an equity distribution. At September 30, 2024 and 2023, the total distributions attributable to Oklahoma state withholding is $1.1 million and $0.6 million, respectively.
For the nine months ended September 30, 2024 as part of the Company’s restructuring plan, we incurred restructuring costs of approximately $8.8 million. For nine months ended September 30, 2023 we incurred restructuring costs of approximately $1.6 million. The costs incurred were primarily related to plans for reductions in workforce to improve operational efficiencies. Restructuring costs recorded in our consolidated statements of operations are presented for the respective periods:
| | Nine Months Ended September 30,
| |
| In thousands of dollars | | 2024 | | | 2023 | |
| | | | | | | |
| Type of Restructuring Cost | | | | | | |
Severance and related benefit costs | | $ | 8,729 | | | $ | 1,485 | |
Office-lease abandonment and relocation | |
| 93 | | |
| 115 | |
| | $ | 8,822 | | | $ | 1,600 | |
The Company has evaluated subsequent events through February 11, 2025, the date the financial statements were issued and noted the events below.
In August 2024, the Company entered into two separate agreements to sell certain East Texas based assets (the “East Texas Sale”) to two third parties. Total combined proceeds from the East Texas Sale totaled $97.0 million, of which $34.5 million was settled in shares of one of the purchasing entities. The East Texas Sale closed in Q4 2024.
In January 2025, the Company received a favorable verdict related to a civil claim against another operator. The court awarded $5.6M to the Company, subject to final appeals by the opposing party.
In January 2025, the Company entered into a definitive merger agreement with Diversified Energy Company PLC (“Diversified”), pursuant to which Diversified will acquire all the outstanding equity interest of the Company for total consideration of approximately $1.3 billion. The transaction is subject to customary closing conditions, including due diligence assessments and other closing requirements. The closing date of the transaction is expected to occur in the first half of 2025.
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