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Accounting Policies, by Policy (Policies)

12 Months Ended

Dec. 31, 2025

Summary of Significant Accounting Policies [Abstract]

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 reserve quantities and estimated future cash flows associated with proved reserves, depletion of proved developed oil and natural gas reserves, asset retirement obligations, accruals for the Company’s oil, natural gas, and NGL revenues and any potential liabilities, the valuation of the Series F Convertible Preferred Stock, $0.01 par value per share (“Series F Preferred Stock”), Series F Preferred Stock Warrants (as defined herein), and the Company’s stock–based compensation performance based awards, the fair value of commodity derivative instruments, the realization of deferred tax assets, and any acquisition–related purchase price allocations.

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, 2025 and 2024, the Company had cash and cash equivalents of less than $0.1 million and $5.2 million, respectively.

Joint Interest and Other Receivables

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 abandonment costs which 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 which are past due.

Oil and Natural Gas Properties

Proved properties. The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, development drilling and completion costs are capitalized when incurred and depleted using the unit–of–production (“UOP”) method based on total estimated proved developed oil and natural gas reserves. The costs of acquiring proved properties are also capitalized and depleted, including leasehold acquisition costs transferred from unproved properties, using the UOP method based on total estimated proved developed and undeveloped reserves.

The Company assesses its proved oil and natural gas properties for impairment whenever circumstances indicate that the carrying value of proved oil and natural gas properties may not be recoverable. In this assessment, 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 (“ASC 820”). 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.

Unproved properties. Under the successful efforts method of accounting for oil and natural gas properties, unproved properties, such as the costs to acquire undeveloped leases, are not subject to depletion until they are transferred to proved properties. The Company transfers leasehold costs to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Additionally, development drilling and completion costs for wells in–progress are excluded from depletion until the related project is completed and proved producing reserves are established.

The following table presents the property balances excluded from the Company’s UOP depletion calculation for the years indicated:

	December 31, 2025		December 31, 2024
	(In thousands)
Acquisition costs	$	32,796	$	29,335
Development costs ⁽¹⁾		25,101		41,127
Total excluded from depletable base	$	57,897	$	70,462

⁽¹⁾

As of December 31, 2025, the majority of the development costs relate to wells which were in the process of being completed. These wells are scheduled to come online throughout the first and second quarters of 2026 and will be reflected in proved properties and the Company’s UOP depletion calculation at that time.

The Company evaluates its unproved properties for impairment on a yearly basis by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by us or other market participants. If circumstances dictate that the carrying value of unproved properties may not be recoverable, the Company performs a recoverability test. If carrying values exceed the undiscounted future net cash flows associated with the unproved reserves, impairment is measured and recorded at fair value, which is generally estimated using the income approach described in ASC 820. 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. Additionally, the Company expenses any costs related to the expiration of unproved leasehold. During the year ended December 31, 2025, the Company recorded $3.4 million related to leases which expired, which is presented as abandonment and impairment of unproved properties expense on its consolidated statement of operations. The Company did not record any abandonment and impairment of unproved properties expense the year ended December 31, 2024.

Exploratory costs. Exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. Under the successful efforts method of accounting, exploratory drilling costs are initially capitalized 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. To date, the Company has not drilled any exploratory wells but may have exploratory drilling in future years.

Other Property and Equipment

As part of the Bayswater Acquisition, the Company acquired several salt–water disposal wells and the associated facilities, equipment, and pipelines (collectively, the “SWD Facilities”). The Company has accounted for the SWD Facilities at its relative fair value allocated to the assets as of March 26, 2025, the closing date of the Bayswater Acquisition, adjusted for the interim settlement statement and final settlement statement, as discussed further below. The Company is depreciating the SWD Facilities using the straight–line method over an estimated 30–year life from May 2023 and 2024, the dates the SWD facilities were constructed. Refer to Note 3 – Acquisitions for a discussion of the Bayswater Acquisition.

Additionally, other property and equipment also includes of vehicles, computer equipment, and office furniture and fixtures which are depreciated using the straight–line method over their estimated useful lives of five 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 general and administrative expenses over the life of the policy and prepaid software licenses and subscriptions which are amortized into general and administrative or lease operating expenses, depending on the type of license or subscription, over the term of the license or subscription.

Debt Issuance Costs

Debt issuance costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Company’s amended and restated reserve–based credit agreement (the “Credit Facility”) with Citibank, N.A. (“Citi”) are capitalized as debt issuance costs, net 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.

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, 2025, none of the Company’s active leases contain purchase or termination options that are reasonably certain to be exercised.

The Company has certain operating leases for office space, vehicles, and equipment used in its daily operations, for which it records the related lease costs as general and administrative or lease operating expenses, depending on the type of lease, on the accompanying consolidated statements of operations. Refer to Note 11 – Leases for further information related to the Company’s operating leases.

Asset Retirement Obligations

The Company’s oil and natural gas properties include estimates of future expenditures to plug and abandon 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 plug and abandonment 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 plug and abandonment 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 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. 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 general and administrative expense.

Additionally, following the close of the Bayswater Acquisition in March 2025, the Company is party to an oil transportation agreement which includes a minimum volume commitment, requiring the Company to transport a fixed determinable quantity of crude oil on a monthly basis. Under the terms of this agreement, the Company may be required to make periodic deficiency payments for any shortfalls in delivering the minimum gross volume to be transported by the counterparty. Additionally, one of the Company’s gas gathering contracts requires a monthly guaranteed payment intended to reimburse the counterparty for costs incurred to connect to the gathering facility. Refer to Note 12 – Commitments and Contingencies for further information related to the Company’s commitment contracts.

Liabilities at Fair Value

The Company has several financial instruments which were evaluated for embedded derivatives and bifurcation in accordance with ASC Topic 815, Derivatives and Hedging (“ASC 815”) at the time of issuance. Pursuant to ASC 815, the Company has determined that the Standby Equity Purchase Agreement (the “SEPA”), convertible promissory note (the “Senior Convertible Note”), the subordinated promissory note (the “Subordinated Note”) Warrants, Series F Preferred Stock Warrants (as defined herein), and certain features of the Series F Preferred Stock should be accounted for at fair value. As a result, the Company has reflected these financial instrument liabilities at their fair value on its consolidated balance sheet and reflects the changes in the fair values of the liabilities as loss on adjustment to fair value – embedded derivatives, debt, and warrants on its consolidated statements of operations. The Company has engaged a third–party valuation expert to assist in preparing the fair value valuations of these financial instruments at each reporting period. 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 Warrants, Series F Preferred Stock, and Series F Preferred Stock Warrants.

Revenue Recognition

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

	Year Ended December 31,
	2025 ⁽¹⁾		2024
	(In thousands)
Crude oil sales	$	204,040	$	6,595
Natural gas sales		9,472		551
NGL sales		28,136		793
Total revenues	$	241,648	$	7,939

⁽¹⁾	Total revenues for the year ended December 31, 2025, include revenue from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025.

The Company recognizes revenue from the sales of crude oil, natural gas, and NGLs at the point that control of the produced oil, natural gas, and NGL volumes are transferred to the purchaser, which may differ depending on the applicable contractual terms. 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 transportation and processing expenses within its consolidated statements of operations. Transportation and processing expenses incurred prior to the transfer of control are recorded gross within transportation and processing expenses in the accompanying consolidated statements of operations. Gathering, transportation, and processing expenses incurred subsequent to the transfer of control are recorded net within crude oil, natural gas, and NGL sales revenues.

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. As such, 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 transportation and processing expenses 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. Typically, the Company relinquishes control at the inlet of the midstream processing facility and recognizes natural gas and NGL revenues based on the agreed upon contracted amount of proceeds received from the midstream processor. As such, the Company recognizes the revenue associated with these contracts net of gathering and processing costs.

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 reflected in oil, natural gas, and NGL accrued revenue on the accompanying consolidated balance sheets and consists of uncollateralized accrued oil, natural gas, and NGL revenue due under normal trade terms, generally requiring payment within 30 days of production. 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.

As discussed above, the Company closed the Bayswater Acquisition in March 2025 and fully took over operations of the assets acquired in the Bayswater Acquisition in the third quarter of 2025. During the integration of the Bayswater Acquisition, the Company renegotiated certain purchaser agreements associated with the assets acquired, and as a result, certain purchasers which were customers at the close of the acquisition are no longer customers. During the second half of 2025, two of the Company’s largest customers accounted for approximately 83% and 10% of its 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. While the loss of a single purchaser may result in a temporary interruption in sales of, or a lower price for, the Company’s production, the Company does not believe the loss of any single purchaser would have a material impact its business because it believes it could readily find alternative purchasers in its producing region.

General and Administrative Expenses

General and administrative 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 lease operating expenses when they are directly attributable to maintaining the production of its operated oil and natural gas properties. For the oil and natural gas properties for which the Company is the operator, it reduces general and administrative 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. general and administrative expenses also include audit, legal, and other professional service fees, investor relations costs, and software expenses.

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 (“ASC 718”). As such, the Company has engaged a third–party valuation expert to assist in preparing the fair value of the PSUs awards 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 of Directors (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 718. The Company has elected to not estimate the forfeiture rate of its RSUs and PSUs in its initial calculation of compensation expense but instead adjusts 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 not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. On this basis, as of December 31, 2025, the Company had a partial valuation allowance of $6.7 million to offset its net deferred tax liabilities.

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 for the years indicated:

	Year Ended December 31,
	2025		2024
	(In thousands)
Non–cash investing activities:
Increase in capital expenditure accruals and accounts payable	$	5,652	$	14,136
Equipment purchased in exchange for note payable	$	560	$	—

Non–cash financing activities:
Common Stock issued to Bayswater as part of Bayswater Acquisition purchase price ⁽¹⁾	$	16,000	$	—
Common Stock issued for SEPA commitment fee ⁽²⁾	$	—	$	600
Common Stock issued upon conversion of Senior Convertible Note ⁽³⁾	$	18,164	$	—
Common Stock issued upon conversion of Series D Preferred Stock	$	8,475	$	6,170
Common Stock issued upon conversion of Series E Preferred Stock	$	—	$	20,000
Common Stock issued upon conversion of Series F Preferred Stock	$	38,490	$	—
Common Stock issued for Series F Preferred Stock dividends ⁽⁴⁾	$	11,269	$	—
Credit facility issuance costs included in accrued liabilities	$	—	$	331
Credit facility issuance costs paid by the issuance of Common Stock ⁽⁵⁾	$	—	$	1,000

Supplemental disclosure:
Cash paid for interest	$	25,259	$	715

⁽¹⁾

The Company issued approximately 3.7 million shares of the Company’s common stock, par value $0.01 per share (“Common Stock”) to Bayswater (as defined herein) as part of the Bayswater Purchase Price (as defined herein). Refer to Note 2 – Acquisitions for a discussion of the Bayswater Acquisition (as defined herein).

⁽²⁾	Pursuant to the SEPA, the Company issued 100,000 shares to YA II PN, LTD., a Cayman Islands exempt limited company (“Yorkville”) as a commitment fee. Refer to Note 14 – Stockholders’ Equity for a discussion of the SEPA.

⁽³⁾	During the year ended December 31, 2025, Yorkville, converted the remaining $11.3 million of the initial $15.0 million Senior Convertible Note in exchange for 2.1 million shares of Common Stock. Refer to Note 10 – Debt for a discussion of the Senior Convertible Note.

⁽⁴⁾	The Company elected to issue shares of Common Stock for the Series F Preferred Stock dividends payable on June 1, September 1, and December 1, 2025. Refer to Note 13 – Mezzanine Equity for a discussion of the Series F Preferred Stock.

⁽⁵⁾	Prior to entering into the reserve–based credit agreement with Citibank N.A. (“Citi”) 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.

Recently Issued Accounting Pronouncements

In December 2023, the FASB issued Accounting Standards Update (“ASU”) 2023–09, Income Taxes (Topic 740) (“ASC 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 has adopted ASU 2023–09 for the annual period ended December 31, 2025 and has conformed its income tax disclosures in Note 18 – Income Taxes to reflect the new requirements.

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 2024–03”), 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.

Recently Issued Tax Legislation

On July 4, 2025, Public Law 119–21, commonly referred to as One Big Beautiful Bill Act (“OBBB”) was signed into law, resulting in several changes to the U.S. federal income tax laws. The legislation includes several changes to federal tax regulations and makes permanent, extends, or modifies certain provisions of Public Law No. 115–97, commonly referred to as the Tax Cuts and Jobs Act. These changes include, among others, permanently restoring earnings before interest, taxes, depreciation, and amortization expense–based business interest deduction limitation, 100% bonus depreciation for certain property and immediate expensing for certain domestic research and experimental expenditures. The Company does not expect the OBBB to have a material effect on income tax expense for the year ending December 31, 2025. All effects of changes in tax legislation are recognized in the consolidated financial statements during the period of enactment. As such, the effects of the OBBB are reflected in the Company’s assessment of its valuation allowance as of December 31, 2025.