NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “we”, “us”, “our”, “the Company”) is presented to assist in understanding our financial statements.

These consolidated financial statements include the accounts of Royale Energy Inc and our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The financial statements and notes are representations of our management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

Description of Business

We are an independent oil and gas producer and we also perform turnkey drilling operations. We own wells and leases in major geological basins located primarily in California, Texas, and Oklahoma, and offer fractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

Use of Estimates

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Estimated quantities of crude oil and condensate, Natural Gas Liquids (“NGLs”) and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 18 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements for further detail.

Other items subject to estimates and assumptions include the carrying amounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation allowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from these estimates.

Liquidity and Going Concern

Management evaluated whether conditions and events, considered in the aggregate, raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date the accompanying consolidated financial statements are issued. The accompanying financial statements have been prepared assuming the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded asset amounts or the amounts and classifications of liabilities that might result from the outcome of this uncertainty.

The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets.

Our 2025 consolidated financial statements reflect a working capital deficiency of $11,550,839, an accumulated deficit of $94,566,369 and recurring net losses from operations. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

Management’s plans to alleviate the going concern by implementing cost control measures that include the reduction of overhead costs and through the sale of non-strategic assets, and to seek additional debt and/or equity financing. There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to us and whether we will generate positive operating cash flow or become profitable. If we are unable to raise sufficient additional funds, we will have to develop and implement a plan to further extend payables and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful.

Revision of Previously Issued Financial Statements

During the preparation of the 2025 consolidated financial statements, immaterial errors were identified related to:  

We assessed the materiality of the errors, both quantitatively and qualitatively, in accordance with the SEC’s Staff Accounting Bulletin No. 99 and Staff Accounting Bulletin No. 108, and concluded the errors were not material to any of our previously issued financial statements. Notwithstanding the results of the assessment, we have revised the applicable items in our previously issued financial statements to correct these misstatements. Accordingly, all consolidated financial information contained in these consolidated financial statements and the accompanying notes have been revised to reflect the corrections. Previously reported financial information will be corrected in future filings, as applicable. 

Restricted Cash

We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. We classify these funds prior to commencement of drilling as restricted cash. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement of cash flows.

Other Receivables, net

Our other receivables consist of receivables from direct working interest investors and industry partners. We account for expected credit losses on receivables using the Current Expected Credit Loss (CECL) methodology. Under this standard, an allowance for expected credit losses is established and adjusted based on historical loss experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The allowance account is increased or decreased in response to changes in these factors, reflecting our best estimate of credit losses over the remaining life of the receivables.

All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2025 and 2024, we established an allowance for expected credit loses of $2,302,873 and $2,194,552, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Revenue Receivables

Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, we have not had issues related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables is not currently necessary.

Allowance for Credit Losses

We measure our allowance for losses on other receivables including, under ASC 326. The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the period indicated:

Equity Method Investments

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method and Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

The Company’s only equity method investment is its holding in the RMX joint venture. At December 31, 2025, the Company had no balance related its investment in RMX, due to previously recognized impairments.

Revenue Recognition

A significant portion of our revenues are derived from the sale of crude oil, condensate, NGL and natural gas under spot and term agreements with our customers as follows:

The pricing in our hydrocarbon sales agreements are determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements of Lease Operating Expense.

We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regard to the sale of our share of production and recognize revenue for the volumes associated with our net production.

We frequently sells a portion of the working interest in each well we drill or participate in to third-party investors and retains a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability as Deferred Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels.

Natural Gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated Statement of Operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation cost is netted directly against revenues. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.

Turnkey Drilling Obligations

We manage these Turnkey Agreements for the participants of the well. The collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. We manage the performance obligation for the well participants and only record revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied.

Other Operating Revenue

For the years ended December 31, 2025 and 2024, we recognized $20,761 and $16,266, respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes.

Oil and Gas Property and Equipment

Successful Efforts

We use the “successful efforts” method to account for our exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalize expenditures for productive wells. We amortize the costs of productive wells under the unit-of-production method.

We carry, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing the reserves and the economic and operating viability of the well. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.

Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Production Cost

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.

The project drilling phase commences with the development of the detailed engineering design and ends when the assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

Impairment

We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations. During 2025 we recorded impairment losses of $27,250, on various capitalized lease and land costs where the carrying value exceeded the estimated fair value. In 2024 we recorded impairment losses of $400,719.

Upon the sale or retirement of a complete field of a proved property, we eliminate the cost from our books, and the resultant gain or loss is recorded to our consolidated statements of operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in our consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.

Asset Retirement Obligations

The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is a Level 3 measurement using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.

Long-Lived Assets Classified as Held for Sale

We classify long-lived assets as Held-for-Sale when the criteria of ASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below:

Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If we retain the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current an asset retirement obligation (“ARO”) (See Note 3, below).

Turnkey Drilling

We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete our obligations and are incurred with any excess booked against our property account to reduce any basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations have been fulfilled.

The contracts require the participants pay us the full contract price upon execution of the agreement. We complete the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating costs. We retain legal title to the lease. The participants purchase a working interest directly in the well bore.

In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant.

A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2025 and 2024, we had Deferred Drilling Obligations of $14,277,496 and $11,457,996, respectively. During 2025, we disposed of $2,755,500 of drilling obligations as we participated in drilling and completion of one gross (0.0035 net) successful oil well in the Texas Permian basin, while incurring expenses of $1,433,351, resulting in a gain of $1,322,149. During 2024, we disposed of $6,562,721 of drilling obligations as we participated in the drilling and completion of four gross (0.0722 net) wells in Texas Permian basin, while incurring expenses of $4,955,044, resulting in a gain of $1,607,677.

If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in restricted cash are amounts for use in completion of turnkey drilling programs in progress.

Equipment and Fixtures

Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred.

Loss Per Share

Basic and diluted losses per share are calculated as follows:

Income Taxes

We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, 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.

The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts.

Fair Value Measurements

According to Fair Value Measurements and Disclosures guidance as provided by ASC 820 and 825, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods subsequent to initial recognition, the reporting entity shall disclose information that enable users of our financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period.

Fair value is defined as 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. In determining fair value, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as consider counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below:

Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities.

Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions.

As of December 31, 2025, we have financial liabilities, including outstanding notes, that have been measured at fair value on a nonrecurring basis. The carrying values of financial instruments comprising cash, payables, and receivables, approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying amounts of cash and cash equivalents, accounts receivable, and other current assets approximate their fair values due to the short-term maturities of these instruments.

As part of the Series B Convertible Preferred Stock restructuring transaction, the Company issued Series 2024 Senior Unsecured Promissory Notes in exchange for approximately 10% of the outstanding Series B shares. These notes have varying interest rate periods:

The fair value of these notes was determined using a discounted cash flow model based on an assumed market interest rate of 11.912%, reflecting the Company’s estimated borrowing rate (Wall Street Journal Prime Rate plus 400 basis points as of October 1, 2024). Based on this valuation methodology, the following table sets out the fair value and carrying value of the notes issued.

The fair value measurement of these notes is classified as Level 3 in the fair value hierarchy due to the use of significant unobservable inputs, including management’s assessment of credit risk and cash flow projections. The carrying amount of these notes will be accreted to their face value over the term using the effective interest rate method.

The carrying values and estimated fair values of these notes were as follows:

Additionally, the restructuring included the issuance of 25,000,000 stock warrants exercisable at $0.10 per share, expiring June 30, 2029. The warrants were valued using the Black-Scholes-Merton model, resulting in a fair value of $0.04 per warrant or an aggregate value of $995,503, which is classified as equity and not a liability for fair value measurement purposes.

See Note 2 – Oil and Gas Properties, Equipment and Fixtures for further discussion of our asset retirement obligations and property transactions.

Accounts Payable and Accrued Expenses

At December 31, 2025 and 2024, the components of accounts payable and accrued expenses consisted of:

Accrued – Non-current

At December 31, 2025 and 2024, we had non-current accrued liabilities of $12,386 and accrued unpaid guaranteed payment of $90,000. These were due to certain Matrix Oil Corp (“Matrix”) principals, from periods prior to the merger with the Matrix entities during March of 2018.

Business Combinations

From time-to-time, we acquire businesses in the oil and gas industry. We primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.

We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.

If the set of assets and activities acquired is not considered a business under GAAP, the acquisition is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values, and no goodwill is recognized. The Pradera Fuego Acquisition was accounted for as an asset acquisition under GAAP.

Changes in Accounting Standards

Recently Adopted

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. We have adopted ASU 2023-09 for the annual period ended December 31, 2025 and have conformed our income tax disclosures in Note 4 to reflect the new requirements.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. The Company adopted this update effective January 1, 2024. See Note 14 - Segments. The adoption and implementation of this standard did not have a material impact on the Company’s disclosures.

Recently Issued, Not Yet Adopted

We have reviewed all other recently issued accounting pronouncements that are not yet effective and have determined that none are currently expected to have a material impact on our consolidated financial statements upon adoption.

In November 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic 220-40) Reporting Comprehensive Income-Expense Disaggregation Disclosures, which broadens the disclosures required for certain costs and expenses in the Company’s annual and interim consolidated financial statements. This ASU is effective prospectively for fiscal years beginning after December 15, 2026, and interim reporting periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating disclosures related to our annual report for fiscal year 2027.