VAALCO ENERGY INC /DE/

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs properties. We have a diversified African-focused portfolio of production development and exploration assets located in Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea, Nigeria, as well as, prior to the Canada Asset Divestment (defined below), producing properties in Canada.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of consolidation – The accompanying consolidated financial statements (“Financial Statements”) include the accounts of the Company and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating and non-operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation.

Use of estimates – The preparation of the Financial Statements in conformity with generally accepted accounting principles in the U.S. (“GAAP”) requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.

Estimates of crude oil, natural gas and NGLs reserves used to estimate depletion expense and impairment charges, as well as to estimate the fair value of assets and liabilities acquired in business combinations, require significant judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information becomes available.

Cash and cash equivalents – Cash and cash equivalents includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks associated with cash and cash equivalents.

Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and estimated timing of usage. As of December 31, 2025, the balance in current restricted cash is for employee-related payroll withholdings, while the long-term restricted cash account represents the funding requirement for the debt service reserve account (“DSRA”) under the 2025 RBL Facility. The DSRA required balance is calculated based on the aggregate amount of scheduled principal payable by the Company and the amount of interest payable outstanding under the 2025 RBL Facility. As of December 31, 2024, the balance in current restricted cash is for an escrow amount representing bank guarantees for customs clearance in Gabon and employee-related payroll withholdings, while the long-term restricted cash includes the balance for charter payment escrow for the FPSO offshore Gabon. In addition, the long-term account also includes an $8.9 million balance for the settlement of a tax audit related to the Svenska Acquisition with a corresponding accrued tax settlement liability recorded and included in Other long-term liabilities in the Consolidated Balance Sheet.

In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $15.6 million in March 2023. The remaining balance of the abandonment fund was unchanged during 2025.

The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the amounts shown in the consolidated statements of cash flows.

Trade, net– The Company’s trade accounts receivable results from sales of crude oil, natural gas and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses and other below.

Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements. For credit loss and other allowances associated with accounts with joint venture owners, see allowance for credit loss and other below.

Egypt receivables and other, net– As of the Merged Concession Effective Date, an effective date adjustment was owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date (as defined herein) (the “Effective Date Adjustment”). The Company recognized a receivable of $67.5 million for the Effective Date Adjustment as of October 2022, based on historical realized prices (the “Backdated Receivable”). The Backdated Receivable was fully settled as of March 31, 2025.

For credit losses associated with Egypt receivables and other, net, see allowance for credit losses and other below.

Value added tax and other receivables, net – The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”).

As of December 31, 2025 and 2024, the outstanding VAT receivable balance was approximately $1.1 million and $2.8 million, net to VAALCO, respectively. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other expense, net” line item of the consolidated statements of operations and comprehensive income. For the allowance associated with VAT, see allowance for credit losses and other below.

Allowance for credit losses and other – On January 1, 2023, the Company adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”). ASU 2016-13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates. All other amounts previously disclosed as allowances for bad debt were transferred to allowances for credit loss and other.

The Company estimates the current expected credit loss and other allowances based primarily using either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance willnot be collected.

The Company has identified the following types of financial assets that are within the scope of ASU 2016-13:

•Trade, net;

•Accounts with joint venture owners, net;

•Egypt receivables and other, net; and

•Loans to employees.

During the years ended December 31, 2025 and 2024, the Company recognized $0.1 million and $7.7 million in credit loss and other allowances, respectively, mainly due to VAT receivables and receivables from joint venture partners.

The following table provides an analysis of the change in the aggregate credit loss and other allowances:

Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon and Cote d’Ivoire, inventories represent the Company's share of crude oil produced and stored on the FSO and the FPSO but unsold at the end of each period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold.

Prepayments and other –Included in “Prepayments and other” line item of the Company’s December 31, 2025 and 2024 consolidated balance sheet are the following assets:

Crude oil, natural gas and NGLs properties and equipment, net – The Company uses the successful efforts method of accounting for crude oil, natural gas and NGLs producing activities.

•Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Interest expense is capitalized for qualifying assets under construction. Capitalized interest costs are included in Crude oil, natural gas and NGLs properties and equipment, net.

•Capitalized equipment, spare parts and other – Capitalized equipment, spare parts and other represents the costs incurred in purchasing and bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle.

•Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block basis under the unit-of-production method based upon estimates of total proved developed reserves. Depletion of leasehold acquisition costs are provided on a block basis under the unit-of-production method based upon estimates of total proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, natural gas and NGLs producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically five years for office and miscellaneous equipment and five to seven years for leasehold improvements.

•Unproved Property Cost– Significant unproved properties are assessed individually for impairment and when events or circumstances indicate that the carrying value of property may not be recovered, the capitalized costs of the related properties would be expensed. The unproved property costs are not subject to depreciation, depletion and amortization, until they are classified as proved properties.

•Impairment – The Company reviews the crude oil, natural gas and NGLs properties and equipment, net for impairment on a block basis whenever events or changes in circumstances indicate that the carrying amount of such properties 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 charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or periods of sustained declines in commodity prices. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value.

Capitalized equipment inventory is reviewed regularly for obsolescence. During the year ended December 31, 2025, we recorded an inventory write-down of $2.4 million for estimated obsolete inventory as well as inventory whose carrying value is in excess of net realizable value and the related expense is included in the “Other operating income (expense), net” line item in the Consolidated Statements of Operations and Comprehensive Income (Loss).

When undeveloped crude oil, natural gas and NGLs leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to unproved property costs in the Etame Marin block in Gabon, Canada, Egypt and in Block P in Equatorial Guinea.

•Assets and Liabilities Held for Sale – The Company classifies disposal groups as held for sale in the period in which all of the following criteria are met: (1) management, having the authority to approve the action, commits to a plan to sell the disposal group; (2) the disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such disposal groups; (3) an active program to locate a buyer or buyers and other actions required to complete the plan to sell the disposal group have been initiated; (4) the sale of the disposal group is probable, and transfer of the disposal group is expected to qualify for recognition as a completed sale, within one year, except if events or circumstances beyond the Company’s control extend the period of time required to sell the disposal group beyond one year; (5) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value; and (6) actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

A disposal group that is classified as held for sale is initially measured at the lower of its carrying amount or fair value less any costs to sell. Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Subsequent changes in the fair value of a disposal group less any costs to sell are reported as an adjustment to the carrying amount of the disposal group, as long as the new carrying amount does not exceed the carrying amount of the asset at the time it was initially classified as held for sale. Depreciation, depletion and amortization expense is not recorded on assets to be divested once they are classified as held for sale. In the initial period in which the disposal group meets the criteria to be classified as held for sale, the assets and liabilities of the disposal group are separately presented as assets held for sale and liabilities held for sale, respectively, in the Consolidated Balance Sheets.

When items of crude oil, natural gas and NGLs properties and equipment are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of crude oil, natural gas and NGLs properties and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale.

Lease commitments– At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. If a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments.

Asset retirement obligations (“ARO”) – The Company has legal obligations to remove tangible equipment and restore land or seabed at the end of crude oil, natural gas and NGLs production operations. The removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of onshore or offshore crude oil, natural gas and NGLs platforms, and capping pipelines. Estimating the future restoration and removal costs requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with crude oil, natural gas and NGLs properties and equipment, net. The Company uses current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil, natural gas and NGLs properties and equipment, net. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related capitalized asset retirement cost or through a charged to earnings, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a units-of-production basis for crude oil, natural gas and NGLs properties and equipment, net production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain.

Revenue recognition– The Company’s revenues are derived from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers.

Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. The Company mainly satisfies its performance obligations at a point in time. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Revenues associated with the sales of the Company’s crude oil, natural gas, condensates and natural gas liquids (“NGLs”) are recognized by reference to actual volumes sold and quoted market prices in active markets for crude oil, natural gas, condensates and NGLs, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable.

Major maintenance activities– Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs.

Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.

Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.

For restricted stock awards, the grant date fair value is determined using the market value of the common stock on the date of grant.

The stock-based compensation expense for equity awards is recognized over the period that services are provided. For awards considered liabilities under US GAAP, awards are measured at fair value on the grant date and remeasured at fair value until the award is settled.

Legal Contingencies – We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue losses associated with legal claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred.

Foreign currency transactions – The U.S. dollar is the functional currency of the Company’s foreign operating subsidiaries except for Canada which has a functional currency of the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income (loss). The Company recognized losses on foreign currency transactions of $0.7 million in 2025, $1.8 million in 2024 and $0.9 million in 2023.

Income taxes – The tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil, which is due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, will not be realized. A valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered are earnings generated in previous periods, forecasted earnings and the expiration period of carryovers.

Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.

The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations and comprehensive income (loss).

Fair value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:

Level 1 – Inputs are observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date.

Level 2 – Inputs are observable market-based inputs or unobservable inputs that are corroborated by market data.

Level 3 – Inputs are unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Nonrecurring Fair Value Measurements– The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, natural gas and NGLs properties and equipment, net, asset retirement assets and liabilities and assets acquired and liabilities assumed in a business combination, and assets and liabilities held for sale. The Company uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When the Company is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows. The expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors, most of which are often outside of management's control. However, assumptions used to reflect a market participant's view of long term prices, costs and other factors and are consistent with assumptions used in the Company's business plans and investment decisions.

Fair value of financial instruments – The Company determines the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs.

See Note 9. Derivatives for further details of the Company’s derivative contracts.

Earnings per Share– Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.

3. NEW ACCOUNTING STANDARDS

Adopted

In December 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in this update improve the transparency of income tax disclosures by requiring (1) consistent categories and greater disaggregation of information in the rate reconciliation and (2) income taxes paid disaggregated by jurisdiction. This update improves the effectiveness and comparability of disclosures by requiring disaggregation by jurisdiction of disclosures of pretax income (or loss) and income tax expense (or benefit). This ASU is to be applied on a prospective basis, with retrospective application permitted. The guidance in this update is effective for fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-09 for the year ended December 31, 2025 on a prospective basis. The adoption of ASU 2023-09 required additional income tax disclosures and did not have an impact on the Company’s consolidated financial position or results of operations.

Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, Accounting Standards Update 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve financial reporting by requiring that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU to our notes to the consolidated financial statements and processes.

In July 2025, the FASB issued ASU 2025-05, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets. The ASU introduces a practical expedient and, for non-public business entities, an accounting policy election to simplify the application of credit loss guidance to short-term receivables and contract assets by allowing consideration of post-balance-sheet collections. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The Company has elected to not adopt the practical expedient. The Company, when estimating its credit losses, will continue to consider available information that is relevant to its assessment of the collectibility of cash flows, including historical losses, current economic conditions, and reasonable and supportable forecasts. Management will continue to monitor changes in the Company’s portfolio, economic conditions, and future guidance issued by the Financial Accounting Standards Board to determine whether election of the practical expedient would be appropriate in future reporting periods.

4. ACQUISITIONS AND DIVESTITURE

Canada Asset Divestment

In December 2025, the Company’s Board of Directors approved the sale of the Company’s oil and gas properties in Canada. As of December 31, 2025, the assets and liabilities associated with the Canada Asset Divestment (defined below) were classified as held for sale on our Consolidated Balance Sheet. The Canada Asset Divestment does not qualify as a discontinued operation under FASB ASC Topic 205, Presentation of Financial Statements, as it does not represent a strategic shift that will have a major effect on the Company's operations or financial results.

Upon classification as held for sale, the Company recorded an impairment loss of $67.2 million to adjust the carrying value of the assets held for sale to their estimated fair value less cost to sell. The impairment loss is presented in the “Impairment loss on assets held for sale” line item in the Consolidated Statements of Operations and Comprehensive Income (Loss). The following table sets forth the carrying value of the assets and liabilities held for sale:

As previously discussed, the Company reviews the crude oil, natural gas and NGLs properties and equipment quarterly at each reporting period or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. Impairment assessments are performed in connection with the preparation of the financial statements, ensuring that recognized losses reflect conditions as of the reporting date. As further discussed above, the Company determined that the Canada Asset Divestment met the criteria for classification as held for sale as of December 31, 2025. This determination constituted a triggering event requiring an impairment assessment, which was performed concurrently with the Company’s periodic impairment evaluation as of December 31, 2025.

On February 4, 2026, the Company entered into an asset purchase agreement (the “Canada APA”) to sell all of our operating assets in Canada (the “Canada Asset Divestment”) to a third party purchaser for a purchase price of $24.4 million

(C$33.4 million) to be settled in cash, subject to customary adjustments. The Canada Asset Divestment closed on February 19, 2026 with an effective date of February 1, 2026 for an adjusted purchase price of $25.5 million (C$34.9 million), subject to additional customary post-closing adjustments. The net cash proceeds from the divestment was primarily used to fund our capital expenditures and for working capital purposes. The Canada Asset Divestment represents the Company’s complete exit of its Canadian oil and gas operations.

Acquisition of Interest in CI-705 Block

In March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire. The Company is the operator of the CI-705 block with a 70% working interest and a 100% paying interest through a commercial carry arrangement and is partnering with two other parties. The CI-705 block is located in the Tano basin, west of the Company's CI-40 Block, where the Baobab and Kossipo oil fields are located. The total amount of acquisition costs for this transaction is approximately $3.0 million.

FPSO Acquisition

In February 2025, the Company, through the joint operating agreement operator, completed the acquisition of the Baobab floating, production, storage and offloading vessel (the “Baobab FPSO”) in Côte d'Ivoire for a total purchase price of $20.0 million, or approximately $6.1 million net cost to the Company.

Svenska Acquisition

On April 30, 2024, the Company completed the acquisition of all of the issued shares in the capital of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (“Svenska”) for a net adjusted purchase price of $40.2 million (the “Svenska Acquisition”). The total purchase price consideration was funded with $40.2 million of the Company’s cash-on-hand. Cash acquired in the business combination included $31.8 million of cash and cash equivalents as well as restricted cash of $8.8 million which nets to $0.4 million cash received on the business combination within the purchase price allocation.

As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, an initial $19.9 million bargain purchase gain was recognized as of the close date. The purchase price allocation was finalized in the fourth quarter of 2024 and the Company made adjustments to the amounts assigned to the net assets acquired based on new information obtained about facts and circumstances that existed as of the Svenska Acquisition date. As a result, the bargain purchase gain was reduced by $6.4 million. The bargain purchase gain is primarily attributable to a stronger forward pricing curve for oil and gas reserves on the date of the closing of the acquisition than was used for the purposes of the negotiations of the purchase price paid for Svenska.

The Svenska Acquisition qualified as a business combination and was accounted for using the acquisition method of accounting. The following tables summarize the cash paid for the purchase price and the final purchase price allocation of the acquisition consideration.

Post-Acquisition Operating Results. The table below summarizes amounts contributed by the Cote d’Ivoire assets acquired in the Svenska Acquisition to the Company's consolidated results for the period from April 30, 2024 through December 31, 2024.

The unaudited pro forma results presented below have been prepared to give effect to the Svenska Acquisition discussed above on the Company’s results of operations for the year ended December 31, 2024 and 2023, as if the acquisition had been consummated on January 1, 2023. The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the Svenska Acquisition had been completed on such date or to project the Company’s results of operations for any future date or period.

(a)The unaudited pro forma net income (loss) for the year ended December 31, 2024 excludes a nonrecurring pro forma adjustment directly attributable to the Svenska Acquisition, consisting of a bargain purchase gain of $13.5 million.

(b) The unaudited pro forma net income (loss) for the year ended December 31, 2023 excludes a nonrecurring pro forma adjustment attributable to the TransGlobe Acquisition, consisting of a bargain purchase gain adjustment of $1.4 million.

5. EARNINGS PER SHARE

Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.

A reconciliation of reported net income (loss) to net income (loss) used in calculating EPS as well as a reconciliation from basic to diluted shares follows:

6. REVENUE

Exploration and production activities of our assets in Gabon, Egypt, Cote d'Ivoire, and Equatorial Guinea are generally governed by PSCs.

Our oil entitlement under the PSCs is generally the sum of cost oil, profit oil and excess cost oil, if applicable. Under the terms of the PSCs, the Company is typically the contractor partner (“Contractor”) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred (“Cost Oil”) and a stipulated share of production after cost recovery (“Profit Oil”).

The Contractor may be obligated to make royalty payments to the host government of each country using a variable percentage based on gross daily production levels. The remaining oil production, after deducting the gross royalty, if any, is split between Cost Oil and Profit Oil. Cost Oil is up to a maximum percentage and is allocated to recover approved operating and capital costs spent on specific projects. Excess Cost Oil, which is Cost Oil less the actual cost recovery, is further shared between the host government and the Contractor. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.

Our share of royalties is paid out of the government's share of production. Additionally, the income tax to which the Contractor is subject to (“Profit Oil Tax”), is deemed to have been paid to the host government as part of the payment of Profit Oil or is captured in the entitled share of Profit Oil production paid in-kind to the host government, and therefore no additional tax burden is due. Under this arrangement taxation is based on a set percentage of average daily production volume.

Gabon

Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements (“COSMA or COSMAs”). Except for internal costs, which are expensed as incurred, there are no upfront costs associated with obtaining a new COSPA or COSMA.

Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO or FSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete.

The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically as operator, the volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the volumes sold exceeded the Company’s ownership interest.

For each lifting completed under a COSPA or COSMA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

The terms of the Etame PSC includes provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price and a shared portion of Profit Oil determined based on daily production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments.

To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment. Payments for royalties are reflected as a reduction in revenues from customers.

With respect to the government’s share of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the consolidated statements of operations and comprehensive income (loss), the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. The amount associated with the Profit Oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported in current income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, which is the period in which it lifts the crude oil. For the years ended December 31, 2025 and 2024, we made total in-kind payments through production liftings of $31.8 million and $30.3 million, respectively. As of December 31, 2025 and 2024, we had foreign income tax payables of $18.8 million and $40.0 million, respectively.

Certain amounts associated with the carried interest in the Etame Marin block are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs that would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues.

The following table presents revenues in Gabon from contracts with customers as well as revenues associated with the obligations under the Etame PSC:

Egypt

Revenues from sales in Egypt are generally made through direct sales to EGPC or through contracts with customers pursuant to crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements (“COSMA or COSMAs”). EGPC and the Company each own a 50% interest, respectively, in the operating company which is a party to the Merged Concession Agreement. EGPC and the Company each also own a 50% interest, respectively, in the operating company that is a party to the South Ghazalat concession agreement.

Customer sales generally occur when sales are directly to EGPC or haphazardly production is sold through a cargo lifting. The Company records EGPC’s share of production as royalties which are netted against revenue, whether EGPC’s share of production arises from EGPC’s share of Profit Oil or excess Cost Oil.

With respect to Egyptian income taxes, these taxes are paid by EGPC on behalf of the Company out of EGPC’s share of production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of the Company are recognized as crude oil revenue and income tax expense.

EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC’s cooperation and approval to schedule liftings. Once liftings occur, the Company has a 30-day collection cycle on liftings as a result of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

In some instances, the Company will borrow or loan production volumes in order to achieve a required amount of crude oil for cargo sales. In these instances, the Company can be in an overlift or underlift position. Regardless of being in an overlift or underlift position, sales are based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds and the Company will record a payable, if in an overlift position, or a receivable, if in an underlift position, based on the fair value of the consideration received or receivable.

The following table presents revenues in Egypt from contracts with customers:

Canada

Prior to the Canada Asset Divestment, customer sales generally occurred on a daily basis when crude oil, natural gas, condensate or NGL’s were sold, normally via pipeline, to a delivery point. There is a single performance obligation (delivering crude oil, natural gas, condensate or NGL’s to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. The Company paid royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime. The Company recorded revenues net of royalties.

Settlement of accounts receivable in Canada occurred on the 25th of the following month following production.

The following table presents revenues in Canada from contracts with customers:

The Company owns a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa. Production generated from the Baobab field is shared under a PSC (the “Cote d'Ivoire PSC”). In addition, in March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire as the operator with a 70% working interest and a 100% paying interest.

Revenues from contracts with customers are generated from sales in Cote d'Ivoire pursuant to crude oil sales and purchase agreements (“COSPAs”), and revenues are recognized when a lifting, as defined below, is completed.

Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete.

The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. The volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the volumes sold exceeded the Company’s ownership interest.

For each lifting completed under the sales and purchase agreement, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Cost Oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the government state oil company. Profit Oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the government of Cote d'Ivoire (the “Ivorian Government”). The Ivorian Governments’ share of Profit Oil attributable to the Company’s equity interest is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. In addition, under the terms of the Cote d'Ivoire PSC, the tax payments to the Ivorian Government are deemed satisfied by its share of the Profit Oil.

The following table presents revenues in Cote d'Ivoire from contracts with customers:

Information about the Company’s most significant customers -

For the years ended December 31, 2025, 2024 and 2023, our revenue concentration by customer for each operating segment are shown on the table below.

(1)For Cote d'Ivoire, reflects sales from April 30, 2024 through December 31, 2024 related to the Svenska Acquisition.

7. INCOME TAXES

Income (loss) before income taxes is attributable as follows:

Provision for income taxes related to income (loss) consists of the following:

The reconciliation of income tax expense (benefit) to income tax at the U.S. statutory rate is as follows:

Income taxes paid (net of refunds received) were as follows:

Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered.

In assessing the realizability of the deferred tax assets, the Company considers all available positive and negative evidence by jurisdiction to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, future operating conditions, particularly as related to prevailing crude oil prices.

On the basis of this evaluation, as of December 31, 2025, a valuation allowance of $203.6 million has been recorded to recognize only the portion of the deferred tax asset that is more likely than not to be realized. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased.

The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows:

(1)This line includes ROU lease asset.

The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2025, it is not practicable to estimate the unrecognized deferred tax liability. However, unrecognized deferred taxes on remittance of these funds are not expected to be material.

The Company has NOL’s, in the following jurisdictions as of December 31, 2025:

The Company recognizes the financial statement benefit of a tax position only after determining that they are more likely than not to sustain the position following an audit. The Company believes that its income tax positions and deductions will be sustained on audit, and thereforeno reserves for uncertain tax positions have been established. Accordingly, no interest or penalties have been accrued as of December 31, 2025 and 2024. The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense.

The Company is subject to income taxation in the United States and various foreign jurisdictions, including Canada. The Company’s Canadian subsidiaries are currently under examination by the Canada Revenue Agency (“CRA”) with respect to the tax treatment of the disposition of shares of certain foreign affiliates for taxation years included in the year ended December 31, 2022.

In January 2026, the Company received an assessment from the CRA related to this examination. The Company is currently evaluating the assessment and available administrative remedies, including the filing of a notice of objection. The Company is also considering this matter in connection with the previously announced sale of the Company’s Canadian assets. As of December 31, 2025, there have been no developments or new information that would require the Company to record an unrecognized tax benefit. Based on currently available information, the Company does not believe that the ultimate resolution of this matter will have a material adverse effect on its consolidated financial position, tax expense, results of operations, or cash flows; however, the final outcome remains uncertain.

For the years ended December 31, 2025,2024 and 2023, the Company is subject to foreign and U.S. federal taxes only, with no allocations made to state and local taxes. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions.

8. CRUDE OIL, NATURAL GAS AND NGLs PROPERTIES AND EQUIPMENT, NET

The Company’s crude oil, natural gas and NGLs properties and equipment, net, at December 31, 2025 and 2024 is comprised of the following:

Unproved property costs

See the table below for the list of unproved property costs at December 31, 2025 and 2024:

At December 31, 2025, the Company classified $31.8 million of net Crude oil, natural gas and NGLs properties and equipment, including unproved property costs of $13.1 million, as “Noncurrent asset held for sale” on the Consolidated Balance Sheet.

Exploration expense

During the year ended December 31, 2025, we incurred exploration expenses of $8.9 million, which included exploratory costs related to a well determined to be not commercially viable in South Ghazalat, the cost of additional seismic data to be used in Block 705 in Cote d’Ivoire, and expenses related to Blocks G and H in Gabon. We had minimal exploration expenses during 2024.

9. DERIVATIVES

We have entered into derivative contracts primarily with counterparties that are also lenders under the 2025 RBL Facility (defined below) to hedge price risk associated with a portion of our oil, natural gas and NGLs production. In addition, pursuant to the terms of the 2025 RBL Facility agreement, if the aggregate borrowings under the 2025 RBL Facility exceeds 35% of the lower of (a) the available total commitments and (b) the applicable borrowing base amount, we are required to enter into commodity price hedge positions covering certain volumes of anticipated future production set out in the banking case. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points. See table below for the list of outstanding contracts as of December 31, 2025:

(a) Natural gas hedge contracts were assumed by the third-party purchaser upon closing of the sale pursuant to the Canada APA.

(b) One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is approximately 25.5 cubic meters standard conditions.

See Note 2. Summary of Significant Accounting Policies for further details on the measurement of our derivative assets at fair value.

The following table sets forth the gain (loss) on derivative instruments on the Company’s consolidated statements of operations and comprehensive income (loss):

10. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations:

Accretion is recorded in the line item “Depreciation, depletion and amortization” on the consolidated statements of operations and comprehensive income (loss).

11. COMMITMENTS AND CONTINGENCIES

Abandonment funding

Gabon

Under the terms of the Etame PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the life of the Etame Marin Block, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In August 2023, an abandonment study was completed which estimated abandonment costs of approximately $77.9 million ($45.9 million, net to VAALCO) on an undiscounted basis. The abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the PSC. At December 31, 2025, $10.7 million ($6.3 million, net to VAALCO) on an undiscounted basis has been funded. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.

In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $15.6 million in March 2023. No other activity occurred in the abandonment funding account through the end of 2025. The Company is working with the Directorate of Hydrocarbons in Gabon to establish a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.

Share Buyback Program

On November 1, 2022, the Company announced that the Company’s Board of Directors formally ratified and approved a share buyback program. The Board of Directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The 10b5-1 Plan provided for an aggregate purchase of currently outstanding common stock up to $30 million over a maximum period of 20 months. Payment for shares repurchased under the share buyback program were funded using the Company's cash on hand and cash flow from operations. The share buyback program was completed on March 12, 2024. Under the share buyback program, we purchased a total of 6,797,711 shares at an average price of $4.41 per share.

Regulatory and Joint Interest Audits and Related Matters

The Company is subject to periodic audits by various government agencies from the international jurisdictions where we operate, including audits by the respective governments and other members of the Company's joint operating agreements.

Merged Concession Agreement

The Company is a party to the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”). In accordance with the Merged Concession Agreement, we were required to make $10.0 million annual modernization payments through February 1, 2026. As of December 31, 2025, all modernization payments had been fully settled either through actual cash payments or through the issuance of credit against receivables owed from EGPC.

The Company also has minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 for a total of $150 million over the 15 year license contract term. Through December 31, 2025, the Company's financial work commitments have exceeded thefive-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.

The amounts that will be paid for such outstanding off-balance sheet financial work commitments as of December 31, 2025 are $10.0 million in 2026, $10.0 million in 2027, $10.0 million in 2028, $10.0 million in 2029, $10.0 million in 2030 and $50.0 million in 2031 and thereafter.

Domestic Market Obligation

Under the terms of the respective PSCs in Gabon and Cote d'Ivoire, the Company can be required to sell to the Government or another entity designated by the Government, a certain percentage of its Profit Oil to meet the needs of the domestic market.

Drilling Rig Commitment

The Company entered into a bareboat charter agreement (the “Bareboat Charter”) during the fourth quarter of 2024 to charter a drilling rig for its drilling program in Gabon. Pursuant to the Bareboat Charter, the Company also entered into a service agreement with a third party for purposes of maintaining and operating the drilling rig on its behalf. The Bareboat Charter commenced on November 2025 upon the mobilization of the drilling rig towards the Company’s first well and has a noncancellable period of 300 days plus five single well options. The Bareboat Charter stipulates fixed day rates and other variable payments.

12. DEBT

In April 2025, the Company drew down $60.0 million under the 2025 RBL Facility. The borrowing accrues interest at a rate of 10.8% per annum which is based on the Term SOFR plus the Applicable Margin of 6.5% per annum. In addition, the borrowing is due to be repaid within three months from the drawdown date with, subject to certain conditions, the option to rollover the debt upon maturity.

As of December 31, 2025, there were $60.0 million of outstanding borrowings under the 2025 RBL Facility. There wereno outstanding borrowings as of December 31, 2024.

In addition, as of December 31, 2025 and 2024, we were in compliance with all of our debt covenants.

2025 RBL Facility

On March 4, 2025, the Company and certain of its subsidiaries (the “Vaalco Energy Group”), entered into a reserves-based facility agreement (the “2025 Facility Agreement”) providing for a senior secured reserve-based revolving credit facility (the “2025 RBL Facility”) with The Standard Bank of South Africa Limited (acting through its Corporate and Investment Banking Division) as agent and security agent, The Standard Bank of South Africa Limited, Isle of Man Branch and the other financial institutions named in the 2025 Facility Agreement (the “Lenders”), providing for the 2025 RBL Facility.

The 2025 RBL Facility had initial aggregate commitments of $190.0 million (the “Initial Total Commitments”) as of March 4, 2025, with an initial borrowing base of $182.0 million, which was further increased to $184.0 million in April 2025 in accordance with the conditions that were met subsequent to entering into the 2025 Facility Agreement. The Initial Total Commitments originally would reduce semi-annually by $19.0 million starting from September 30, 2026. The borrowing base amount is calculated pursuant to the 2025 RBL Facility Agreement and redetermined on March 31 and September 30 of each year beginning June 30, 2025 and in certain circumstances, other interim triggers set out in the 2025 Facility Agreement. In 2025, we completed our June 30 and September 30 borrowing base redeterminations, which increased the borrowing base to $190.0 million.

The Company may, at any time prior to the date falling 30 months from the date of the 2025 Facility Agreement and subject to the conditions and process set out in the 2025 RBL Facility Agreement, give notice to the agent to increase the Initial Total Commitment up to a maximum amount of $300.0 million. Effective October 17, 2025, the Lenders approved to (i) extend the first date on which the Initial Total Commitments will be reduced from September 30, 2026 to March 31, 2027, and (ii) update the semi-annual commitment reduction amounts from $19.0 million to $10.0 million on March 31, 2027, and $22.5 million starting on September 30, 2027.

As of December 31, 2025, we had $190.0 million of aggregate facility commitments and $130.0 million of available borrowing capacity under the 2025 RBL Facility.

In addition, subject to certain conditions precedent, certain existing Lenders under the 2025 RBL Facility agreed to increase their initial commitment effective January 23, 2026 from $190.0 million to $255.0 million. The increase in commitments was undertaken with the existing accordion feature included in the 2025 RBL Facility.

On February 4, 2026, the Company borrowed an additional $65.0 million under the 2025 RBL Facility. The borrowing accrues interest at a rate of 10.2% per annum which is based on the Term SOFR plus the Applicable Margin of 6.5% per annum. In addition, the borrowing is due to be repaid within one month from the drawdown date with, subject to certain conditions, the option to rollover the debt upon maturity.

Each loan under the 2025 RBL Facility will bear interest at a rate equal to Term Secured Overnight Financing Rate (“SOFR”) plus the Applicable Margin of (i)6.50%, from the date of the 2025 Facility Agreement until the date on which the renovation and repair of the floating production storage and offloading tanker facility named Baobab Ivorian MV10 FPSO for use in connection with the development of the Baobab field (the “Baobab FPSO Renovation”) meets certain completion tests defined in the 2025 RBL Facility Agreement and (ii) thereafter,6.00% until the Final Maturity Date (defined below). We shall pay the accrued interest on the last day of each applicable interest period, which interest period may be, at our option, one, three or six months or such other period as agreed to between us and the Lenders.

The 2025 RBL Facility will mature on the earlier of (i) March 4, 2031, which is the sixth anniversary of the date of the 2025 Facility Agreement and (ii) the Reserve Tail Date (the “Final Maturity Date”). The Reserve Tail Date is the last day of the calculation period immediately preceding the first calculation period in which the aggregate remaining reserves for all of the borrowing base assets are projected in the then current banking case to be less than 25% of the initial approved reserves.

The 2025 RBL Facility is secured against certain assets of the Company and the other obligors under the 2025 Facility Agreement. The security package includes security over the shares in the obligors (other than in the Company), hedging agreements, intercompany loans, insurances, offtake agreements relating to the borrowing base assets and project accounts.

The 2025 RBL Facility Agreement contains certain financial covenants, including that, beginning on June 30, 2025 and then as of each March 31 and September 30 until the Final Maturity Date, the ratio of Total Net Indebtedness to EBITDAX (each defined in the 2025 Facility Agreement) for the trailing 12 months shall not exceed 3.0 x. Additionally, following the Baobab FPSO renovation completion date, the debt service coverage ratio for the trailing 12 months commencing on the day immediately following each March 31 and September 30 (and any interim redetermination date) until the Final Maturity Date shall be at least 1.2:1. The Company also provides a liquidity forecast for the Vaalco Energy Group which shall demonstrate that the total corporate sources equal or exceed the total corporate uses. The liquidity forecast is delivered quarterly during the Baobab FPSO renovation period and otherwise on each redetermination of the banking case and any proposed distribution.

The Company is required to pay a quarterly commitment fee equal to (i)35% per annum of the Applicable Margin on the daily amount of the difference (if any) by which the borrowing base amount exceeds the then-outstanding amount of loans, plus (ii)20% per annum of the Applicable Margin on the daily amount by which the then-total commitments exceeds the higher of the total outstanding amount of loans and the borrowing base amount. The Company is also required to pay customary technical and modelling bank fees, agency fees and security agent fees. The 2025 Facility Agreement also contains customary information covenants as well as affirmative and negative covenants subject to customary threshold and materiality which include, among others, compliance with laws (including environmental laws, sanctions and anti-corruption laws), delivery of quarterly and annual financial statements and compliance certificates, no change of business, no merger and maintenance of corporate existence, field preservations and related contracts relating to the borrowing base assets, maintenance of insurance, entry into certain derivatives contracts which are regulated by the 2025 Facility Agreement and the hedging policy, restrictions on the incurrence of liens, indebtedness, asset dispositions, acquisitions, restricted payments, entry into offtake agreements and other customary covenants. If the aggregate borrowings exceeds 35% of the lower of (a) the available total commitments and (b) the applicable borrowing base amount, we are also required to enter into commodity price hedge positions covering certain volumes of anticipated future production set out in the banking case. There are other covenants that make the Company’s ability to pay dividends and to enter into certain acquisitions and disposition transactions subject to certain conditions. These covenants are subject to a number of limitations and exceptions.

Additionally, the 2025 RBL Facility Agreement contains customary events of default, including non-payment and borrowing base deficiency, funding shortfall subject to certain liquidity cure rights, breach of financial covenants, misrepresentation, insolvency, changes in ownership or business, litigation, cross default, expropriation of any borrowing base assets, political events, cessation of production and the occurrence of a material adverse effect. The 2025 Facility Agreement also contains events of default related to the failure to complete the Baobab FPSO Renovation by the Baobab FPSO Renovation long stop date determined in the 2025 Facility Agreement and the failure to renew any field license on substantially the same terms three months before the expiration of such field license and if a change of operator occurs. The events of default contains thresholds and remedy periods customary for credit facilities of this nature. If the obligors do not comply with the financial and other covenants relating to non-payment, sanctions, anti-corruption, loans and guarantee or tax in the 2025 Facility Agreement, the Lenders may require immediate payment of all amounts outstanding under the 2025 Facility Agreement and any outstanding unfunded commitments may be terminated. In addition, if any principal amount payable is not paid upon due date, interest shall accrue on the overdue amount from the due date up to the date of the actual payment at an additional interest rate of 2% per annum, and such interest shall be immediately payable on demand.

Fair Value Measurement

The fair value of the 2025 RBL Facility approximates its respective carrying amount as its interest rate is variable and reflective of current market rates. The fair value measurement for the 2025 RBL Facility represents Level 2 inputs.

13. LEASES

Under the leasing standard that became effective January 1, 2019, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments.

Operating leases

The Company is currently a party to three operating lease agreements for the corporate and Egypt offices and transportation equipment. The remaining lease term for these agreements ranges from 35 to 60 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for certain equipment used in the joint operations includes the gross amount of the lease components.

The transportation equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the number of days or hours the asset is deployed. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities.

Financing leases

The Company is currently a party to several financing lease agreements for the FSO and generators and marine vessels used in the operations of the Etame Marin block. The remaining lease term for these agreements ranges from 1 to 81 months months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities.

All leases

For all leases that contain an option to extend the initial lease term, the Company has evaluated whether it is reasonably certain that the Company will extend the lease beyond the initial lease term. When the Company believes it is reasonably certain it will utilize these leased assets beyond the initial lease term, those payments have been included in the calculation of the ROU assets and liabilities. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. The Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.

For the years ended December 31, 2025, 2024 and 2023, the components of the lease costs and supplemental information was as follows:

(1)Represents depreciation and interest associated with financing leases.

(2)Represents short term leases under contracts that are 1 year or less where a ROU asset and lease liability are not required to be recorded.

(3)Variable costs represent differences between minimum lease costs and actual lease costs incurred under lease contracts.

The table below describes the presentation of the total lease cost on the Company’s consolidated statements of operations and other comprehensive income (loss). As discussed above, the Company’s joint venture owners are required to reimburse the Company for their share of certain expenses, including certain lease costs.

The following table describes the future maturities of the Company’s operating and financing lease liabilities at December 31, 2025:

Under the joint operating agreements, other joint venture owners are obligated to fund approximately $41.3 million of the $104.5 million in future lease liabilities as of December 31, 2025.

14. ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:

(a) The table excludes $0.2 million of current portion of asset retirement obligations associated with assets held for sale.

15. SHAREHOLDERS’ EQUITY

Dividend Policy

The following table is a schedule of dividends paid during 2025:

Preferred stock– Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. No shares of preferred stock were issued and outstanding as of December 31, 2025 or 2024.

Treasury stock

Please see discussion on the Company’s share buyback program under Note 11. Commitments and Contingencies.

16. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS

The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Board of Directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At December 31, 2025,483,624 shares were available for future grants.

For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.

As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the years ended December 31, 2024 and 2023, the Company settled in cash $0.2 million and $0.4 million, respectively, for SARsno amounts settled for 2025. During the years ended December 31,2024 and 2023, the Company received in cash $0.4 million and $0.7 million, respectively from stock option exercises, no amounts received in 2025.

Performance restricted stock units

The Company grants shares of its common stock to its executives in the form of shares of performance restricted stock unit (“PSS”) awards. These awards are measured at the fair value of the underlying shares on the date of grant and recognized ratably as compensation expense over a period ofthree years, vesting in three equal parts on the anniversaries from the date of grant to the extent that the performance hurdles and service condition are met.

In June 2025, the Company granted 789,976 shares performance-based restricted stock awards (“PSS”) to certain executives of the Company. The awards had a grant date fair value of approximately $1.8 million using a Monte Carlo Valuation model. The Company will recognize the entire $1.8 million of compensation expense for this award, regardless of whether such conditions are met, over the requisite service period unless units are forfeited during the period.

For each PSS stock award, one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $3.86 per share; PSS awards with respect to one-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $4.45 per share; and PSS awards with respect to the remaining one-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $5.12 per share. These PSS awards contain a requisite service period of 10 years.

During the year ended December 31, 2025, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of the PSS awards under the Monte Carlo model.

PSS awards activity associated with the Monte Carlo model for the year ended December 31, 2025 is provided below:

The intrinsic value of a performance stock option awards is the amount that the current market value of the underlying stock exceeds the exercise price of the award.

As of December 31, 2025, unrecognized compensation cost related to unvested vesting awards was $1.3 million, which is expected to be recognized over a weighted average period of 1.75 years.

Stock options and performance shares

Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors that is generally athree-year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles.

In June 2024, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 549,495 shares at an exercise price of $5.96 per share and a life often years. For each performance stock option award, one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $6.85 per share; performance stock options with respect to one-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $7.88 per share; and performance stock options with respect to the remaining one-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $9.09 per share. These awards are option awards that contain a market condition. Compensation cost for such awards is recognized ratably over the derived service period and compensation cost related to awards with a market condition will not be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such performance criteria.

There wereno stock option grants during the year ended December 31, 2025.

During the year ended December 31, 2024 and 2023 the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of performance stock options grants under the Monte Carlo model.

Performance stock options activity associated with the Monte Carlo model for the year ended December 31, 2025 is provided below:

The intrinsic value of a performance stock option awards is the amount that the current market value of the underlying stock exceeds the exercise price of the award.

As of December 31, 2025, unrecognized compensation cost related to outstanding performance stock option awards was $0.6 million, which is expected to be recognized over a weighted average period of 1.27 years.

The Company’s regular stock options (stock options without a performance condition) awards associated with the Black-Scholes model were all exercised in 2024. The intrinsic value of a stock option is the amount that the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of stock options exercised in 2024 and 2023 was $0.5 million and $0.6 million, respectively.

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally athree-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant).

The following is the activity for the Company's restricted stock for the year ended December 31, 2025:

The total fair value of vested restricted stock awards during 2025, 2024 and 2023 was $2.2 million, $5.0 million, and $1.5 million, respectively. The weighted average grant date fair value per share of restricted stock awards, which vested during 2025, 2024 and 2023, was $5.39, $4.42 and $3.92, respectively.

As of December 31, 2025, unrecognized compensation cost related to restricted stock totaled $3.8 million and is expected to be recognized over a weighted average period of less than 1.41 years.

RSUs were issued to directors, officers and employees of TransGlobe in the ordinary course of business prior to the TransGlobe Acquisition. Each RSU vests annually over athree-year period.

RSU activity for the year ended December 31, 2025 is presented in the table below:

The total fair value of vested RSU awards during 2025 was $0.3 million. The weighted average grant date fair value per share of RSU, which vested during 2025, was $4.78.

As of December 31, 2025, unrecognized compensation cost related to RSUs totaled $1.7 million and is expected to be recognized over a weighted average period of 0.75 years.

During the year ended December 31, 2025, 194,771 shares were added to treasury as a result of tax withholding on the vesting of restricted stock and RSU’s.

PSUs are similar to RSUs except that they originally contained a performance factor affecting the vesting percentage. For the PSUs that remained outstanding following the effective time of the TransGlobe Acquisition, the applicable vesting percentage was determined by the TransGlobe Board of Directors to be 200% for PSUs granted in 2022 and 2023; and 64.4% for PSUs granted in 2024. All PSUs granted vest on the third anniversary of their grant date.

PSU activity for the year ended December 31, 2025 is presented in the table below:

During the year ended December 31, 2025, 3,671 shares were added to treasury shares as a result of tax withholding on the vesting of PSU’s.

DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's Board of Directors. At December 31, 2025, there are approximately 101,313 DSUs outstanding, which are vested but not converted.

Stock appreciation rights (“SARs”)

SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s Board of Directors.

SARs are considered liabilities under US GAAP and the awards are measured at fair value on the grant date and remeasured at fair value until the award is settled.

The intrinsic value of a SAR is the amount that the current market value of the underlying stock exceeds the exercise price of the award. The intrinsic value of SARs exercised in 2024 and 2023 was $0.2 million, and 0.4 million respectively. During the years ended December 31, 2025 and 2024, the Company didnot grant SARs to employees or directors. On February 28, 2024, all remaining SAR awards were exercised.

Other Benefit Plans

The Company has adopted forms of change in control agreements for certain named executive officers of the Company as well as a severance plan for its Houston-based non-executive employees. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements will be entitled to receive 100% and 50%, respectively, of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months. In addition, certain named executive officers will receive 75% of their target bonus. Some of the named executive officers are also entitled to severance payments under their employment agreements.

17. RELATED PARTY TRANSACTIONS

VAALCO has entered into various agreements with related parties. The Company paid approximately $0.3 million and $0.2 million to these related parties for each of the years ended December 31, 2025 and 2024, respectively. The amounts in both 2025 and 2024 were primarily for contract engineering services paid to an entity owned and controlled by a related party of an officer of the Company.

18. OTHER COMPREHENSIVE INCOME (LOSS)

At December 31, 2025, the Company’s accumulated other comprehensive loss was $0.5 million. All of the Company’s other comprehensive income (loss) arises from the currency translation of VAALCO Energy Canada, Inc. to USD.

The components of accumulated other comprehensive income (loss) are as follows:

19. SEGMENT INFORMATION

The Company’s operations are based in Gabon, Egypt, Cote d'Ivoire, Canada and Equatorial Guinea. Each of thereportable operating segments are organized and managed based upon geographic location. The Company’s Chief Executive Officer, who is the chief operating decision maker (“CODM”) evaluates segment performance based on the operation of each geographic segment separately primarily based on Operating income (loss) and allocates financial and capital resources for each segment predominantly in the annual budget and forecasting process. The CODM also considers budget-to-actual variances on a quarterly basis for the performance measure when making decisions about allocating capital and personnel to the segments.

The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production. Corporate and other is primarily corporate and operations support costs that are not allocated to the reportable operating segments and are shown in the tables to reconcile the business segments to consolidated totals. No transactions occurred between operating segments. “Other operating income (expense)” below are those items that are included in Net income (loss) but are not regularly provided to the CODM, or are reported to the CODM but are not considered to be significant segment expenses.

Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.

Segment activity of continuing operations for the years ended December 31, 2025,2024 and 2023 and long-lived assets and segment assets at December 31, 2025 and 2024 are as follows:

(a) At December 31, 2025, the Company classified$31.8 million of net Crude oil, natural gas and NGLs properties as “Noncurrent Assets held for sale” on the Consolidated Balance Sheet.

20. SUBSEQUENT EVENTS