Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2 – Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from these estimates.

These estimates and assumptions include estimates for reserves of credit losses, accruals for potential liabilities, estimates and assumptions made in valuing assets and debt instruments issued in the Merger, the valuation of the SEPA, Senior Convertible Note, the Subordinated Note, and warrants issued in the third quarter of 2024, discussed further in Note 10 – Debt, the fair value of its derivative instruments, and the realization of deferred tax assets.

Cash and Cash Equivalents

Cash and cash equivalents are defined by the Company as short-term, highly liquid investments which have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. The carrying value of cash and cash equivalents approximate the fair value due to the short-term nature of these instruments. The Company may have cash balances which exceed the federal deposit insurance limits of $250,000, creating a potential credit risk. To mitigate this risk, the Company maintains its cash and cash equivalents with high quality financial institutions; therefore, it does not anticipate incurring any losses related to these credit risks. As of December 31, 2024 and 2023, the Company had cash and cash equivalents of $5.2 million and $13.0 million, respectively.

Accounts Receivable

Oil, natural gas, and NGL revenue receivable consists of uncollateralized accrued oil, natural gas, and NGL revenue due under normal trade terms, generally requiring payment within 30 days of production. Joint interest and other receivables consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date and, at times, receivables from the counterparties to the Company’s derivative contracts. In the Company’s capacity as operator, it incurs development, exploration, operating, and plug and abandon (“P&A”) costs that are billed to its partners based on their respective working interests. For receivables from joint interest owners, the Company typically has the ability to withhold revenue distributions to recover any unpaid joint operations billings that are past due.

The Company did not have any producing wells prior to the NRO Acquisition (as defined herein), which closed on October 1, 2024. Following the NRO Acquisition, during the fourth quarter of 2024, two of the Company’s largest customers accounted for approximately 80% and 15% of its oil, natural gas, and NGL revenues. Those same two customers accounted for approximately 78% and 20% of the Company’s accrued oil, natural gas, and NGL revenues. The Company is exposed to credit risk in the event of nonpayment by the purchasers of its production, all of which are concentrated in energy-related industries and may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. However, the Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil, natural gas, and NGL are fungible products with well-established markets and numerous purchasers.

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals, and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred.

In successful efforts accounting, exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. If proved reserves are not found, the costs related to unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If the Company determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. The Company reviews the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and oil, are capitalized.

The costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed oil and natural gas reserves. Costs for wells in the process of being drilled, significant nonproducing properties, and in-process development projects are excluded from depletion until the related project is completed and proved producing reserves are established or, if unsuccessful, abandonments expense is recognized. The costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves.

The following table presents the costs of unproved properties excluded from the Company’s UOP depreciation calculation as of December 31, 2024 and the periods such costs were incurred:

			December 31,
	Total		2024		2023
	(In thousands)
Acquisition costs	$	29,335	$	630	$	28,705
Development costs (1)		41,127		41,127		—
Total costs incurred	$	70,462	$	41,757	$	28,705

⁽¹⁾ As of December 31, 2024, $38.0 million of development costs relate to wells which were in the process of being completed. These wells began producing in February 2025 and will be reflected in proved properties and the Company’s UOP depreciation calculation in the first quarter of 2025.

Proceeds from the sales of individual oil and natural gas properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

When circumstances indicate that the carrying value of proved oil and natural gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Topic (“ASC”) 820, Fair Value Measurements. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital.

Other Property and Equipment

Other property and equipment primarily consists of office furniture and fixtures which are depreciated using the straight line method over their estimated useful lives of 5 years.

Derivative Instruments

The Company utilizes commodity derivative instruments to reduce its exposure to crude oil and natural gas price volatility for a portion of its estimated production from its proved, developed, producing oil and natural gas properties. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model. Refer to Note 6 - Fair Value Measurements for a further discussion of the fair value of the Company’s derivative instruments.

The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds or payments related to the early termination of derivative contracts during the period are recognized as net gain or loss on derivatives, as applicable, in the consolidated statements of operations. Refer to Note 4 - Derivative Instruments for a discussion of the Company’s outstanding derivative instruments.

Prepaid Expenses and Other Current Assets

The Company’s prepaid expenses and other current assets primarily consists of premiums paid for its various insurance packages, including commercial packages, general liability, and Director and Officer policies, and performance bonds which are amortized into G&A over the life of the policy.

Deferred Financing Costs

Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Company’s Credit Facility (as defined herein) are capitalized to other non–current assets on the accompanying balance sheets and amortized to interest expense on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Refer to Note 10 - Debt for a discussion of the Company’s Credit Facility.

Notes Receivable

As discussed further below in Note 3 – Discontinued Operations, the Company sold all of its cryptocurrency miners (the “Mining Equipment”) in January 2024. The consideration included $1.0 million in deferred cash payments (the “Deferred Purchase Price”), to be paid out of (a) 20% of the monthly net revenues received by the buyer associated with or otherwise attributable to the Mining Equipment until the aggregate amount of such payments equals $250,000 and (b) thereafter, 50% of the monthly net revenues received by the buyer associated with or otherwise attributable to the Mining Equipment until the aggregate amount of such payments equals the Deferred Purchase Price, plus accrued interest. As of December 31, 2024, the Company presents the Deferred Purchase Price payment as a note receivable on its consolidated balance sheet, $0.5 million of which is classified as current and $0.2 million of which is classified as non–current, based on when the payments are expected. The Company did not have a note receivable balance on its consolidated balance sheet as of December 31, 2023.

Leases

The Company capitalizes its operating leases as right-of-use (“ROU”) assets and lease liabilities on the accompanying consolidated balance sheets and recognizes the fixed minimum lease costs for its operating leases on a straight-line basis over the lease term in accordance with ASC Topic 842, Leases (“ASC 842”). The Company does not recognize leases with initial lease terms less than or equal to 12 months on the balance sheet and only includes those short-term leases as part of its lease-related disclosures. Additionally, the Company does not include any of its variable lease costs in the calculation of its ROU assets and lease liabilities, instead variable costs are expensed as incurred

The Company makes certain assumptions and judgments when determining its ROU assets and lease liabilities. When determining whether a contract contains a lease, the Company considers whether there is an identified asset that is physically distinct, whether the supplier has substantive substitution rights, whether the Company has the right to obtain substantially all of the economic benefits from the use of the asset, and whether it has the right to control the asset. Certain of the Company’s leases include one or more options to renew the lease, with renewal terms that can extend the lease term for additional years. When determining if renewals should be included in the lease term to be recognized, the Company utilizes the reasonably certain threshold, therefore, certain of the leases included in the calculation of its ROU assets and lease liabilities could include optional renewal periods for which it is not contractually obligated. Additionally, the Company must estimate its incremental borrowing rate when the implicit rate is not stated in the lease agreement and cannot be readily determined. As of December 31, 2024, none of the Company’s active leases contain purchase or termination options that are reasonably certain to be exercised.

The Company has several operating leases for office space and vehicles used in its daily operations, for which it records the related lease costs as G&A expenses on the accompanying consolidated statements of operations.

Asset Retirement Obligations

The Company’s oil and natural gas properties include estimates of future expenditures to P&A wells, pipelines, platforms, and other related facilities after the reserves have been depleted. The Company recognizes the present value of the asset retirement obligation costs as a liability when it is incurred or assumed (acquired) and an increase to its capitalized oil and natural gas properties. The capitalized asset retirement obligation costs are depleted over the productive lives of the oil and natural gas properties while the asset retirement obligation liability is accreted to the expected settlement value over the productive lives of the oil and natural gas properties. Upon settlement, the difference between the recorded liability amount and the amount of costs incurred will be recognized as an adjustment to the capitalized cost of oil and natural gas properties.

The determination of future asset retirement obligations requires estimates of the future costs of removal and restoration, productive lives of the oil and natural gas properties based on reserve estimates, and future inflation rates. Estimated costs consider historical experience, third-party estimates, and government regulatory requirements but do not consider salvage values. These costs could be subject to revisions in subsequent years due to changes in regulatory requirements, the estimated P&A cost, and the estimated timing of the oil and natural gas property retirement. In subsequent periods, if the estimate of the asset retirement obligation liability changes, the Company records an adjustment to both the asset retirement obligation liability and the oil and natural gas property carrying value. Additionally, the Company estimates the credit-risk adjusted discount rate, which is applied to the future inflated P&A costs to determine the discounted present value which is recognized as the initial liability. The determined credit-risk adjusted discount rate is also subsequently applied to accrete the liability. Refer to Note 8 - Asset Retirement Obligations for further information related to the Company’s asset retirement obligations.

Commitments and Contingencies

The Company recognizes a liability for loss contingencies when it believes it is probable a liability has been incurred, and the amount can be reasonably estimated. If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range, the Company accrues that amount. When no amount within the range is a better estimate than any other amount the Company accrues the minimum amount in the range.

Liabilities at Fair Value

As discussed in Note 10 – Debt and Note 14 – Common Stock, on September 30, 2024, the Company entered into the SEPA and issued the Senior Convertible Note, the Subordinated Note, and the Subordinated Note Warrants. All three of these agreements contain features which must be evaluated for embedded derivatives and bifurcation pursuant to ASC Topic 815, Derivatives and Hedging (“ASC 815”). As such, the Company has elected to account for the SEPA, the Senior Convertible Note, the Subordinated Note, and the Subordinated Note Warrants using the fair value option. Refer to Note 6 – Fair Value Measurements for a full discussion of the fair values of the SEPA, the Senior Convertible Note, the Subordinated Note, and the Subordinated Note Warrants.

Revenue Recognition

The Company recognizes revenue from the sales of oil, natural gas, and NGLs at the point that control of the produced oil, natural gas, and NGL volumes are transferred to the customer.

The following table presents the Company’s oil, natural gas, and NGL revenue disaggregated by revenue stream:

	Year Ended December 31,
	2024		2023
	(In thousands)
Oil revenue	$	6,595	$	—
Natural gas revenue		551		—
NGL revenue		793		—
Total revenues	$	7,939	$	—

The Company considers the transfer of control to have occurred when the production is delivered to the purchaser because at that time, the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the oil, natural gas, or NGL production. Transfer of control dictates the presentation of the Company’s gathering, transportation, and processing expenses within its consolidated statements of operations. Gathering, transportation, and processing expenses incurred prior to the transfer of control are recorded gross within gathering, transportation, and processing in the accompanying statements of operations.

Additionally, the Company has made an accounting election to exclude certain qualifying taxes collected from customers and remitted to governmental authorities from its reported revenues and is presenting those amounts as a component of operating expense in the accompanying consolidated statements of operations. The amounts due from purchasers are accrued in oil, natural gas, and NGL revenue accounts receivable on the accompanying consolidated balance sheets. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Additionally, the Company has determined that product returns or refunds are very rare and will account for them as they occur, and it generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specification.

Oil revenue contracts. The majority of the Company’s oil revenue contracts are structured so that the Company delivers production at the wellhead or other contractually agreed-upon delivery point, at which time the purchaser takes custody, title, and risk of loss of the product, and the Company receives a specified index price from the purchaser with no deduction. Therefore, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser and records the third-party transportation costs as a component of operating expense in the accompanying consolidated statements of operations.

Natural gas and NGLs revenue contracts. Under the Company’s natural gas processing contracts, the Company delivers natural gas to a processing entity at the wellhead or the inlet of the processing entity’s system. In these contracts, the Company may elect to take residue gas and/or NGLs in-kind at the tailgate of the processing plant and subsequently market the product. Through the marketing process, the Company delivers the product to the purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. This purchaser can be the natural gas processor or the processor can market the product on the Company’s behalf to a third-party purchaser. In both scenarios, the Company is the principal in the transaction as control of the product remains with the Company throughout the process and any fees paid to the processor are considered to be for a distinct service with an identifiable benefit that is sufficiently separable. Therefore, the Company recognizes revenue when control transfers to the ultimate purchaser at the delivery point based on the index price received from the purchaser and records the gathering, processing, and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as a component of operating expense in the accompanying consolidated statements of operations.

General and Administrative Expenses

General and administrative (“G&A”) expenses consist of overhead, including salaries, incentive compensation, benefits for the Company’s corporate staff, costs of maintaining its headquarters, and costs of managing its production and development operations. The Company records a certain portion of its salaries, wages, and benefits as LOE when they are directly attributable to maintaining the production of its operated oil and natural gas properties. For oil and natural gas properties for which the Company is the operator, it reduces G&A expenses for reimbursements received from other working interest owners for the portion of costs and allowable overhead incurred during the drilling and production phases of the property. G&A expenses also include software fees and audit, legal, and other professional service fees. Additionally, the Company could be subject to legal actions and claims arising in the ordinary course of business, which, if considered probable and reasonably estimable, would require a contingent liability to be recorded as G&A expense.

Stock-based Compensation

The Company’s stock–based compensation awards are classified as either equity or liability awards in accordance with GAAP. The fair value of an equity–classified award is determined at the grant date and is amortized to general and administrative expense on a graded attribution basis over the vesting period of the award. 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 over the vesting period of the award.

Additionally, the Company grants performance stock awards (“PSUs”), which vest and become earned upon the achievement of certain performance goals based on the Company’s relative total shareholder return as compared to the performance peer group during the performance period, which represents a market condition per ASC Topic 718, Compensation—Stock Compensation. As such, the fair value of the PSUs awards is determined by a third party using a Monte Carlo simulation model as of the grant date. Per the PSU agreements, these awards can be settled in either stock or cash, as determined by the Compensation Committee of the Board (the “Committee”); however, unless the Committee determines otherwise, these PSUs will be settled in stock; therefore, the Company classified the PSUs as equity awards.

The Company recognizes compensation expense related to equity–classified and liability–classified awards using the straight-line method over the requisite service period during which the employee, board member, director, or advisor is required to provide services in exchange for the award in accordance with ASC Topic 718, Compensation - Stock Compensation. The Company has elected to not estimate the forfeiture rate of its RSUs and PSUs in its initial calculation of compensation expense, but instead will adjust compensation expense for forfeitures as they occur. Refer to Note 16 - Long-Term Incentive Compensation for a further discussion of the Company’s RSUs and PSUs.

Income Taxes

The Company accounts for income taxes using the asset and liability method whereby deferred tax assets are recognized for deductible temporary differences, and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their respective tax basis. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. As of December 31, 2024, the Company had a full valuation allowance to offset its net deferred tax assets.

Earnings (Loss) Per Common Share

The two–class method of computing earnings per share is required for entities that have participating securities. The two–class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. The Company’s Series D Preferred Stock (as defined herein) is a participating security and the Company’s Series E Preferred Stock (as defined herein) was considered a participating security when the shares were outstanding during the year ended December 31, 2023. These participating securities do not have a contractual obligation to share in the Company’s losses. Therefore, in periods of net loss, no portion of such losses are allocated to participating securities.

Basic earnings (loss) per common share (“EPS”) is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of Common Stock outstanding each period.

Dilutive EPS is calculated by dividing adjusted net income (loss) attributable to common stockholders by the weighted average number of shares of Common Stock outstanding each period, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) Series D Preferred Stock, (ii) Series E Preferred Stock, when the shares were outstanding during the year ended December 31, 2023, (iii) warrants to purchase Common Stock, and (iv) exercisable Common Stock options. Diluted EPS reflects the dilutive effect of the participating securities using the two–class method or the treasury stock method, whichever is more dilutive.

Basic and diluted earnings (loss) attributable to common stockholders is the same for the year ended December 31, 2024 and 2023 because the Company has only incurred losses and all potentially dilutive securities are anti–dilutive.

The following table presents the potentially dilutive securities which were not included in the computation of diluted earnings (loss) attributable to common stockholders for the year ended December 31, 2024 because their inclusion would be anti–dilutive:

Potentially Dilutive Security	Quantity		Stated Value Per Share		Total Value or Stated Value		Assumed Conversion Price		Resulting Common Shares
Merger Options, restricted stock units, and performance stock units (1)		9,337,631	$	—	$	—	$	—		1,337,631
Common stock warrants		227,148,205		—		—		—		8,494,177
Series D Preferred Stock		14,457		1,000		14,456,680		5.00		2,891,336
Senior Convertible Note (2)		—		—		11,251,508		7.79		1,444,353
Total										14,167,497

(1)	Not exercisable or vested as of December 31, 2024. Refer to Note 15 – Common Stock Options and Warrants for a discussion of the Merger Options (as defined herein) and Note 16 – Long–Term Incentive Compensation for a discussion of the restricted stock units and performance stock units.
(2)	Reflects the conversion option of the Senior Convertible Note, pursuant to the SEPA. Refer to Note 10 – Debt for a discussion of the Senior Convertible Note and Note 14 – Common Stock for a discussion of the SEPA.

The following table presents the potentially dilutive securities which were not included in the computation of diluted earnings (loss) attributable to common stockholders for the year ended December 31, 2023 because their inclusion would be anti–dilutive:

Potentially Dilutive Security	Quantity		Stated Value Per Share		Total Value or Stated Value		Assumed Conversion Price		Resulting Common Shares
Common stock options and restricted stock units (1)		8,547,574	$	—	$	—	$	—		547,574
Common stock warrants		386,569,653		—		—		—		13,529,938
Series D Preferred Stock		20,627		1,000		20,627,130		5.00		4,125,426
Series E Preferred Stock		20,000		1,000		20,000,000		5.00		4,000,000
Total										22,202,938

⁽¹⁾ Not exercisable or vested as of December 31, 2023. Refer to Note 15 – Common Stock Options and Warrants for a discussion of the Merger Options and Note 16 – Long–Term Incentive Compensation for a discussion of the restricted stock units.

Supplemental Disclosures of Cash Flow Information

The following table presents non–cash investing and financing activities and supplemental cash flow disclosures relating to the cash paid for interest and income taxes for the periods presented:

	Year Ended December 31,
	2024			2023
	(In thousands)
Non–cash investing and financing activities:
Common Stock issued upon conversion of Series D Preferred Stock	$	6,170		$	—
Common Stock issued upon conversion of Series E Preferred Stock	$	20,000		$	—
Capital expenditures included in accrued liabilities	$	(14,136	)	$	—
Common Stock issued for SEPA commitment fee (1)	$	600		$	—
Credit facility issuance costs paid by the issuance of Common Stock (2)	$	1,000		$	—
Credit facility issuance costs included in accrued liabilities	$	331		$	—
Cryptocurrency mining equipment and deposits acquired in the Merger	$	—		$	20,761
Secured convertible debentures assumed in the Merger	$	—		$	1,981
SBA loan payable acquired assumed in the Merger	$	—		$	150
Membership interests converted into shares of Common Stock	$	—		$	(607	)
Common Stock issued at Merger	$	—		$	9,928
Series D Preferred Stock issued at Merger	$	—		$	3,209
Common Stock and warrants issued in Exok option acquisition	$	—		$	7,289
Common Stock issued in satisfaction of share issuance obligation	$	—		$	2,007
Common Stock issued in conversion of AR Debentures	$	—		$	5,775
Reclassification of increase in value of warrant liabilities in equity	$	—		$	39,780
Supplemental disclosure:
Cash paid for interest (3)	$	715		$	121
Cash paid for income taxes	$	—		$	—

(1)	Pursuant to the SEPA, the Company issued 100,000 shares to Yorkville as a commitment fee. Refer to Note 14 – Common Stock for a discussion of the SEPA.
(2)	Prior to entering into the Credit Facility (as defined below) agreement in December 2024, the Company issued 120,048 shares to Yorkville as a consent fee. Refer to Note 10 – Debt for a discussion of the credit facility.
(3)	For the year ended December 31, 2024, includes amounts paid for redemption premium and minimum return premium. Refer to Note 10 – Debt for a further discussion.

Recently Issued Accounting Pronouncements

In December 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”) to expand the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning January 1, 2025, with early adoption permitted. The Company is currently evaluating the potential effect that the updated standard will have on its financial statement disclosures.

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2023-03”), which requires the disclosure of specific information about certain costs and expenses. ASU 2024-03 is effective for annual periods beginning January 1, 2027, with early adoption permitted. The Company is currently evaluating the potential effect that the updated standard will have on its financial statement disclosures.