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Item 9A. Controls and Procedures

2026-03-16 compared with 2025-03-17 · 600 added, 570 removed, 1434 unchanged (45% of the section changed)

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Management, including our CEO and CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K.

Based on this evaluation, our CEO and CFO have concluded that the Company’s disclosure controls and procedures were not effective as of December 31, 2024 due to the material weaknesses in our internal control over financial reporting described below.

Based on this evaluation, our CEO and CFO have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2025.

Management’s Annual Report on Internal Control Over Financial Reporting

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Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of annual or interim financial statements will not be prevented or detected on a timely basis.

The Company’s management, with participation of the CEO and CFO, under the oversight of our Board of Directors, evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025 using the COSO framework.

Based on that evaluation, our management concluded that the Company’s internal control over financial reporting was not effective as of December 31, 2024 due to the material weaknesses in internal control over financial reporting described below.

Management identified the following material weaknesses in internal control over financial reporting as of December 31, 2024.

• The Company had ineffective general information technology controls (“GITCs”) that support the consistent operation of the Company’s information technology (“IT”) systems, specific to its procure-to-pay system.

As a result, automated process-level controls and manual controls dependent upon the accuracy and completeness of information derived from that IT system were also ineffective because they could have been adversely impacted;

• The Company did not effectively design, implement, or operate process-level control activities related to its financial reporting process, specific to its procure-to-pay process.

Management concluded that these material weaknesses were primarily due to an ineffective control environment that resulted in ineffective risk assessment:

• The Company did not have a sufficient number of trained resources with expertise in and responsibility and accountability for the design, implementation, operation and documentation of internal control over financial reporting and IT systems.

• The Company did not have an effective risk assessment process as we did not adequately assess and manage the risks to our operations following the implementation of the procure-to-pay system, which affected our financial reporting, and we did not establish effective internal control over the procurement process, including risks resulting from the reliance on a third-party service provider, or changes in the external environment and business operations, at a sufficient level of detail to identify all relevant risks of material misstatement to the consolidated financial statements and design and implement internal controls that responded to those risks.

The material weaknesses identified did not result in any misstatements in the consolidated financial statements or disclosures for any interim periods during or for the annual period ended December 31, 2024;

however, a reasonable possibility exists that material misstatements in the Company’s financial statements will not be prevented or detected on a timely basis.

The Company’s independent registered public accounting firm, KPMG LLP (“KPMG”), who audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG’s report appears beginning on page F- 5 of this Annual Report on Form 10-K.

As previously disclosed, on April 30, 2024, we completed the acquisition of Svenska, which is operated under its own set of internal controls.

We are currently integrating this acquisition into our control environment.

In executing this integration, we are analyzing, evaluating and, where appropriate, making changes in controls and procedures in a manner commensurate with the size, complexity and scale of operations subsequent to the acquisition.

We expect to complete the Svenska integration in fiscal year 2025.

SEC guidance permits management to omit an assessment of an acquired business’s internal control over financial reporting from management’s assessment of internal control over financial reporting for a period not to exceed one year from date of acquisition.

Consequently, we excluded Svenska from our assessment of internal control over financial reporting as of December 31, 2024.

Svenska accounted for 20% of our consolidated total assets at December 31, 2024 and 20% of our consolidated operating revenue for the year ended December 31, 2024.

Remediation Activities

We have strengthened our internal control over financial reporting for our year-end closing and reporting process and are committed to ensuring that our controls continue to mature and operate effectively.

Our Board of Directors and management have prioritized the implementation of a remediation plan, taking the necessary actions to address the root causes that contributed to our material weaknesses and other deficiencies identified and to establish and maintain effective internal control over financial reporting.

The following actions and plans have been undertaken or are being undertaken:

• We continued to hire and train our employees to reinforce the importance of a strong control environment and clearly communicate expectations to emphasize responsibilities and the technical requirements for internal controls.

• We continued to enhance the design of existing control activities and implemented additional process-level control activities, including related GITCs.

• We enhanced user access provisioning and monitoring controls for certain IT systems to enforce appropriate system access as well as controls supporting change management.

We are committed to ensuring that our internal control over financial reporting is designed and operating effectively.

Management believes the efforts taken to date to enhance the design and effectiveness of controls have been robust and have increased our overall ability to mitigate material financial risk.

In fiscal year 2025 we expect to continue to enhance our internal control over financial reporting, including the following:

• Continuing to recruit key positions within our technology, accounting, business operations and other support functions with appropriate qualified experience and IT knowledge to enhance our risk assessment processes and internal control capabilities, allow for appropriate change management, and provide appropriate oversight and reviews.

• Designing and implementing a continuous risk assessment process to identify and assess risks of material misstatement and ensure that the impacted financial reporting processes and related internal controls are properly designed and in place to respond to those risks in our financial reporting.

• Working to establish a comprehensive GITC risk evaluation process and invest in people and technology to address gaps in IT Systems Security controls, IT Systems Change Management controls, and IT Systems Batch/Program Monitoring controls, including design of controls to address gaps over our GITC’s for our procure-to-pay system, which we plan to start implementing in first quarter of 2025.

Although we intend to complete the remediation process as promptly as possible, we cannot at this time estimate how long it will take to remediate the material weaknesses described above.

We may discover additional material weaknesses that require additional time and resources to remediate, and we may decide to take additional measures to address the material weaknesses or modify the remediation steps described above.

In addition, while certain of the activities described above have continued to enhance our internal control over financial reporting, certain of these newly designed controls have not operated effectively for a sufficient period of time to be able to conclude on effectiveness.

We remain committed to continue investing significant time and resources and taking actions to remediate the material weaknesses in our internal control over financial reporting as we work to further enhance our control environment.

Until these material weaknesses are remediated, we plan to continue to perform additional analyses and other procedures to ensure that our consolidated financial statements are prepared in accordance with U.S.

Based on the evaluation, our management concluded that, the Company’s internal control over financial reporting was effective as of December 31, 2025.

Remediation of Prior Material Weaknesses

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2024, our management concluded that there were material weaknesses in our internal control over financial reporting related to general information technology controls, effectiveness of control environment, risk assessment and design and process-level controls.

In response to the identified material weakness at December 31, 2024, our management, with oversight from our Audit Committee, made the following changes in its financial reporting processes in 2025:

• We strengthened IT controls by adding resources and reallocating staff to improve risk assessment, change management, and IT oversight.

• We enhanced our efforts to design and implement a continuous risk-assessment process to identify and address risks of material misstatement and to ensure controls are properly designed and operating effectively.

• We established and implemented a comprehensive risk assessment process over general information technology controls, which continues to be refined as part of our ongoing monitoring activities.

• We hired a new IT Director and management has reviewed IT general controls with the IT Director to provide visibility into control design and align responsibilities for ongoing monitoring of controls.

After completing our testing of the design and operational effectiveness of these controls, our management concluded that we fully remediated the previously identified material weaknesses as of December 31, 2025.

Our internal controls over financial reporting as of December 31, 2025 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this Annual Report.

KPMG LLP has provided an attestation report on the Company’s internal control over financial reporting which is included in Item 8 of this Annual Report.

Changes in Internal Control over Financial Reporting

Other than the material weaknesses discussed above, no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended December 31, 2024 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Other than as stated above, no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Other Information

During the year ended December 31, 2024 , none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act).

During the quarter ended December 31, 2025 , none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted , terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act).

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

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Houston, Texas ;

Report of Independent Registered Public Accounting Firm (BDO USA, LLP;

Houston, Texas;

Report of Independent Registered Public Accounting Firm Over Internal Controls over Financial Reporting (KPMG LLP;

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(furnished as Exhibit 1 to TransGlobe Energy Corporation’s Report of Foreign Private Issuer on Form 6-k furnished on March 24, 2022, and incorporated herein by reference)

Amended and Restated Facility Agreement, by and among VAALCO Energy, Inc., VAALCO Gabon (Etame), Inc., VAALCO Gabon, SA, Glencore Energy UK Ltd., the Law Debenture Trust Corporation P.L.C., and the other financial institutions named therein, dated October 3, 2023 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 6, 2023, and incorporated herein by reference).

Crude Oil Sale and Marketing Agreement, by and between VAAALCO Gabon S.A.

Crude Oil Sale and Marketing Agreement, by and between VA ALCO Gabon S.A.

and Glencore Energy UK Ltd., dated May 20, 2022 (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on August 10, 2022, and incorporated herein by reference).

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and Matthew Powers (filed as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed on August 9, 2024, and incorporated herein by reference).

Borrowing Base Facility Agreement by and among VAALCO Energy, Inc., as the Original Borrower, The Financial Institutions listed in Schedule 1 thereto, as the Original Lenders, The Standard Bank of South Africa Limited, Isle of Man Branch, as the Mandated Lead Arranger, and The Standard Bank of South Africa Limited, as the Agent, dated March 4, 2025.

Insider Trading Policy .

Form of 2025 Restricted Stock Award Agreement under the VAALCO Energy, Inc.

2020 Long Term Incentive Plan (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on August 11, 2025, and incorporated herein by reference).

Asset Purchase Agreement, by and among VAALCO Energy Canada, Inc., Petrus Resources Corp., and, solely for the purposes of Section 9.7 therein, Petrus Resources LTD., dated February 4, 2026.

(filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 10, 2026, and incorporated herein by reference).

Insider Trading Policy (filed as Exhibit 19.1 to the Company’s Annual Report on Form 10-K filed on March 17, 2025 and incorporated herein by reference).

List of subsidiaries of the Company.

Consent of BDO USA, P.C.

Consent of KPMG LLP

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— Independent Petroleum Engineers.

Consent of GLJ Ltd.

— Independent Petroleum Engineers.

Sarbanes-Oxley Section 302 certification of Principal Executive Officer.

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Sarbanes-Oxley Section 906 certification of Principal Financial Officer.

Clawback Policy .

Clawback Policy (filed as Exhibit 97.1 to the Company’s Annual Report on Form 10-K filed on March 17, 2025 and incorporated herein by reference).

Report of Netherland, Sewell & Associates, Inc.

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(International Properties) - Cote d'Ivoire

Report of GLJ Ltd.

Report of Netherland, Sewell & Associates, Inc.

(International Properties) - Canada

101.INS(a) Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

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We have audited the accompanying consolidated balance sheets of VAALCO Energy, Inc.

and subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2024, and the related notes (collectively, the consolidated financial statements).

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2024, in conformity with U.S.

and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements).

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S.

generally accepted accounting principles.

We also have audited the adjustments to the 2022 consolidated financial statements to retrospectively apply the change in accounting due to the adoption of Accounting Standards Update No.

2023-07, Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures, as described in Note 3.

In our opinion, such adjustments are appropriate and have been properly applied.

We were not engaged to audit, review, or apply any procedures to the 2022 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2022 consolidated financial statements taken as a whole.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 17, 2025 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 16, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

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The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Assessment of the impact of estimated crude oil, natural gas and natural gas liquids (NGLs) proved reserves on depletion expense related to crude oil and natural gas properties

As discussed in Note 2 to the consolidated financial statements, the Company determines depletion of crude oil and natural gas properties on a block basis under the unit-of-production method based upon estimates of proved reserves.

Assessment of the impact of estimated crude oil, natural gas and natural gas liquids (NGLs) proved reserves on depletion expense related to crude oil, natural gas and NGLs properties

As discussed in Note 2 to the consolidated financial statements, the Company determines depletion of crude oil, natural gas and NGLs properties on a block basis under the unit-of-production method based upon estimates of proved reserves.

For the year ended December 31, 2025, the Company recorded depreciation, depletion and amortization expense of $110 million.

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The Company engages independent reserve engineer specialists to estimate proved reserves, which are an input to the calculation of depletion.

We identified the assessment of the impact of estimated crude oil, natural gas and NGLs proved reserves on depletion expense related to crude oil and natural gas properties as a critical audit matter.

We identified the assessment of the impact of estimated crude oil, natural gas and NGLs proved reserves on depletion expense related to crude oil, natural gas and NGLs properties as a critical audit matter.

Changes in assumptions used to estimate the proved reserves could have had a significant impact on depletion expense.

Complex auditor judgment was required in evaluating the Company’s estimate of proved reserves.

Complex auditor judgment was required in evaluating the Company’s estimates of proved reserves.

Specifically, auditor judgment was required to evaluate the assumptions used by the Company related to future production and future operating and capital costs.

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We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion process, including controls over the estimation of proved reserves.

We evaluated the professional qualifications and knowledge, skills, and ability of the Company’s internal reserve engineers and the independent reserve engineer specialists and the independent reserve engineering firms engaged by the Company.

We evaluated the relationship of the independent reserve engineer specialists and independent reserve engineering firms to the Company.

We evaluated the relationship of the independent reserve engineer specialists and independent reserve engineering firm to the Company.

We analyzed and assessed the determination of depletion expense for compliance with industry and regulatory standards.

We assessed compliance of the methodology used by the Company’s independent reserve engineer specialists to estimate proved reserves with industry and regulatory standards.

We read and considered the report of the Company’s independent reserve engineering firms in connection with our evaluation of the Company’s proved reserve estimates.

We read and considered the report of the Company’s independent reserve engineering firm in connection with our evaluation of the Company’s proved reserve estimates.

We compared future production to historical production rates.

We evaluated the future operating and capital costs by comparing them to historical costs.

Fair value of oil and gas properties acquired in the Svenska business combination

As discussed in Note 4 to the consolidated financial statements, on April 30, 2024, the Company completed an acquisition of Svenska Petroleum Exploration Aktiebolag (Svenska acquisition), for a total consideration of $40.2 million.

The transaction was accounted for as a business combination using the acquisition method.

Under the acquisition method, the assets acquired and liabilities assumed were recorded at their acquisition date fair values.

As a result of the transaction the Company acquired oil and gas properties, which were recognized at their acquisition date fair value of $99.2 million.

The fair value of oil and gas properties were valued using the income approach.

The estimation of oil and gas reserves requires the expertise of reserve engineer specialists, who take into consideration future production, future operating and capital costs, and forecasted commodity prices inclusive of price differentials.

The Company engages independent reserve engineer specialists to estimate oil and gas reserves, which are an input to the fair value of the acquired oil and gas properties.

We identified the evaluation of the acquisition-date fair value of the oil and gas properties acquired in the Svenska acquisition as a critical audit matter.

Complex auditor judgment was required in evaluating the key assumptions used to estimate the fair value of the oil and gas properties as changes to those assumptions could have had a significant effect on the fair value.

The income approach utilized a risk adjusted discounted cash flow model, which included key assumptions related to future production, future operating and capital costs, forecasted commodity prices inclusive of price differentials, risk adjustment factors, and the discount rate.

Estimating oil and gas reserves requires the expertise of independent reserve engineer specialists.

Additionally, the audit effort associated with evaluating the forecasted commodity prices, risk adjustment factors, and the discount rate required specialized skills and knowledge.

Evaluation of the recoverability of certain crude oil, natural gas and NGLs producing properties

As discussed in Note 2 to the consolidated financial statements, the Company performs impairment tests with respect to its crude oil, natural gas and NGLs producing properties on an asset group basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable.

If there is an indication the carrying amount of the crude oil, natural gas and NGLs producing properties may not be recovered, the Company estimates the undiscounted future net cash flows and compares this to the carrying value of the crude oil and natural gas property.

If the sum of the expected undiscounted future net 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.

Estimated future net cash flows are based on assumptions such as forecasted production, forecasted commodity prices inclusive of price differentials, and development and operating costs.

As a result of these tests, no impairments were recorded during the year ended December 31, 2025 for the Company’s crude oil, natural gas and NGLs producing properties, excluding properties held for sale.

We identified the evaluation of the estimate of undiscounted future net cash flows from the related proved and probable reserves, used to assess the recoverability of certain crude oil and natural gas producing properties, as a critical audit matter.

Subjective auditor judgment was required in the evaluation of the estimate of undiscounted future net cash flows from the related proved and probable reserves, due to (1) uncertainty associated with future commodity prices and estimated future production, (2) judgment inherent in forecasting development and operating costs, and (3) subjectivity in determining the risk adjustment factors associated with reserve volumes.

The following are the primary procedures we performed to address this critical audit matter.

We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s acquisition-date valuation process, including controls related to the determination of the key assumptions, as noted above, used to measure the fair value of the acquired oil and gas properties.

We assessed compliance of the methodology used by the Company’s independent reserve engineer specialists to estimate oil and gas reserves with industry and regulatory standards.

We compared the future production to historical Svenska production rates.

We evaluated the future operating and capital costs used by the Company by comparing them to Svenska’s historical costs incurred.

We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s impairment of crude oil, natural gas and NGLs producing properties process, including controls over the Company’s proved and probable reserve estimation process.

We evaluated the professional qualifications and knowledge, skills, and ability of the Company’s internal reserve engineers, the independent reserve engineer specialists, and the independent reserve engineering firm engaged by the Company.

We evaluated the relationships of the independent reserve engineer specialists and independent reserve engineering firm to the Company.

We analyzed and assessed the estimate of undiscounted future net cash flows from the related proved and probable reserves for compliance with industry and regulatory standards.

We assessed compliance of the methodology used by the Company’s independent reserve engineer specialists to estimate proved and probable reserves with industry and regulatory standards.

We read and considered the report of the Company’s independent reserve engineering firm in connection with our evaluation of the Company’s proved and probable reserves estimate.

We evaluated the Company’s undiscounted future net cash flows analysis related to forecasted production, and development and operating costs by comparing to historical results and future development plans.

We evaluated the relevant price differentials used by the Company by comparing them to historical results.

We evaluated the relationship of the independent reserve engineer specialists and the independent reserve engineering firm to the Company.

We read and considered the report of the Company’s independent reserve engineering firm in connection with our evaluation of the Company’s oil and gas reserve estimates.

In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in:

• evaluating the forecasted commodity prices by comparing them to an independently developed range of forward price estimates using data from analysts and other industry sources

• evaluating the risk adjustment factors by comparing them to third party publications of risk adjustment factors utilized by market participants

• evaluating the discount rate by comparing it to a discount rate range that was independently developed using publicly available market data for comparable entities.

We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the forecasted commodity prices, by comparing them to an independently developed range of forward price estimates using data from analysts and other industry sources, and the risk adjustment factors associated with reserve volumes, by comparing them to third party publications of risk adjustment factors utilized by market participants.

We have served as the Company’s auditor since 2023.

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Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

VAALCO Energy, Inc.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited, before the effects of the adjustments to retrospectively apply the change in accounting due to the adoption of Accounting Standards Update 2023-07, Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures (“ASU 2023-07”), as described in Notes 3 and 5, the accompanying consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows of VAALCO Energy, Inc.

(the “Company”) for the year ended December 31, 2022 (the 2022 consolidated financial statements before the effects of the change in accounting due to the adoption of ASU 2023-07 described in Notes 3 and 5 are not presented herein).

In our opinion, the 2022 consolidated financial statements, before the effects of the adjustments to retrospectively apply the change in accounting due to the adoption of ASU 2023-07 described in Notes 3 and 5, present fairly, in all material respects, the Company’s results of operations and cash flows for the year ended December 31, 2022 , in conformity with accounting principles generally accepted in the United States of America.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the change in accounting due to the adoption of ASU 2023-07 described in Notes 3 and 5 and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied.

Those adjustments were audited by KPMG LLP.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management.

Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit.

We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S.

federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB.

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.

Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.

Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that our audit provides a reasonable basis for our opinion.

/s/ BDO USA, LLP

We served as the Company’s auditor from 2016 to 2023.

Houston, Texas

April 6, 2023

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors

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and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, because of the effect of the material weakness, described below, on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2024, and the related notes (collectively, the consolidated financial statements), and our report dated March 17, 2025 expressed an unqualified opinion on those consolidated financial statements.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

A material weakness related to control deficiencies in general information technology controls and process-level controls within the accounts payable financial reporting process which were caused by an ineffective control environment that resulted in ineffective risk assessment, which has been identified and included in management’s assessment.

The material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2024 consolidated financial statements, and this report does not affect our report on those consolidated financial statements.

The Company acquired Svenska Petroleum Exploration Aktiebolag during 2024, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2024, Svenska Petroleum Exploration Aktiebolag’s internal control over financial reporting associated with 20% of total assets and 20% of total revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2024.

Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Svenska Petroleum Exploration Aktiebolag.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated March 16, 2026 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

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VAALCO ENERGY, INC.

AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

(in thousands, except share amounts) 2025 2024

Current assets:

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Accounts with joint venture owners, net of allowance for credit losses of $ 2.7 million and $ 1.5 million, respectively

Egypt receivables and other, net of allowances for credit loss and other of $ 0.0 million and $ 4.6 million, respectively

35,763 45,942

Egypt receivables and other 2,277 35,763

Crude oil inventory 1,774 9,441

Prepayments and other 24,370 14,973

Current assets held for sale 179 —

Total current assets 132,980 237,927

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Other long-term assets 7,362 1,209

Noncurrent assets held for sale 31,826 —

Total assets $ 913,375 $ 954,950

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Foreign income taxes payable 19,656 42,043

Current liabilities held for sale 183 —

Total current liabilities 192,000 181,728

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Deferred tax liabilities 63,630 93,904

Long-term debt 60,000 —

Other long-term liabilities — 17,863

Noncurrent liabilities held for sale 7,403 —

Total liabilities 469,878 453,367

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Additional paid-in capital 368,536 362,578

Accumulated other comprehensive income (loss) ( 4,962 ) 2,880

Accumulated other comprehensive loss ( 498 ) ( 4,962 )

Less treasury stock, 18,759,403 and 18,560,931 shares, respectively, at cost

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Depreciation, depletion and amortization 109,978 143,034 115,302

Impairment loss on assets held for sale 67,224 — —

General and administrative expense 33,089 29,684 23,840

Credit (recovery) losses and other 6,304 ( 4,906 ) 3,082

Credit losses (recovery) and other 106 6,304 ( 4,906 )

Total operating costs and expenses 377,488 342,570 296,842

Other operating expense, net 78 433 38

Operating income 136,496 158,657 171,276

Other operating income (expense), net ( 2,391 ) 78 433

Operating income (loss) ( 20,607 ) 136,496 158,657

Other income (expense):

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Interest expense, net ( 8,243 ) ( 3,732 ) ( 6,452 )

Bargain purchase gain 13,532 ( 1,412 ) 10,819

Other income (expense), net ( 5,754 ) ( 894 ) ( 18,939 )

Bargain purchase gain and measurement period adjustment — 13,532 ( 1,412 )

Other expense, net ( 595 ) ( 5,754 ) ( 894 )

Total other income (expense), net ( 5,962 ) 3,301 ( 8,526 )

Income before income taxes 139,797 150,131 123,310

Income (loss) before income taxes ( 26,569 ) 139,797 150,131

Income tax expense 14,822 81,307 89,777

Net income $ 58,490 $ 60,354 $ 51,890

Net income (loss) $ ( 41,391 ) $ 58,490 $ 60,354

Other comprehensive income (loss)

Currency translation adjustments 4,464 ( 7,842 ) 1,701

Comprehensive income $ 50,648 $ 62,055 $ 53,069

Basic net income per share:

Net income per share $ 0.56 $ 0.56 $ 0.74

Comprehensive income (loss) $ ( 36,927 ) $ 50,648 $ 62,055

Basic net income (loss) per share:

Net income (loss) per share $ ( 0.40 ) $ 0.56 $ 0.56

Basic weighted average shares outstanding 104,055 103,669 106,376

Diluted net income per share:

Net income per share $ 0.56 $ 0.56 $ 0.73

Diluted net income (loss) per share:

Net income (loss) per share $ ( 0.40 ) $ 0.56 $ 0.56

Diluted weighted average shares outstanding 104,055 103,747 106,555

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Stock-based compensation expense — — — 3,410 — — — 3,410

Conversion of Liability Awards to Equity — — — 5,336 — — — 5,336

Acquisition of TransGlobe 49,307 — 4,931 269,214 — — — 274,145

Treasury stock — ( 5,421 ) — — — ( 23,570 ) — ( 23,570 )

Dividend distributions — — — — — ( 26,772 ) ( 26,772 )

Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023 — — — — — — ( 3,120 ) ( 3,120 )

Other comprehensive income 1,701 — — 1,701

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Dividend distributions — — — — — — ( 26,215 ) ( 26,215 )

Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023 — — — — — — ( 3,120 ) ( 3,120 )

Other comprehensive income — — — — 1,701 — — 1,701

Other comprehensive loss — — — — ( 7,842 ) — — ( 7,842 )

Net income — — — — — — 58,490 58,490

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Dividend distributions — — — — — — ( 26,480 ) ( 26,480 )

Other comprehensive loss — — — — ( 7,842 ) — — ( 7,842 )

Net income — — — — — — 58,490 58,490

Other comprehensive income — — — — 4,464 — — 4,464

Net income (loss) — — — — — — ( 41,391 ) ( 41,391 )

Balance at December 31, 2025 123,018 ( 18,759 ) $ 12,302 $ 368,536 $ ( 498 ) $ ( 78,733 ) $ 141,890 $ 443,497

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CASH FLOWS FROM OPERATING ACTIVITIES:

Net income $ 58,490 $ 60,354 $ 51,890

Adjustments to reconcile net income to net cash provided by operating activities:

Net income (loss) $ ( 41,391 ) $ 58,490 $ 60,354

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion and amortization 109,978 143,034 115,302

Bargain purchase gain ( 13,532 ) 1,412 ( 10,819 )

Exploration expense 48 1,841 —

Bargain purchase gain and measurement period adjustment — ( 13,532 ) 1,412

Impairment loss on assets held for sale 67,224 — —

Non-cash exploration expense 2,409 48 1,841

Deferred taxes ( 29,427 ) ( 16,785 ) ( 2,864 )

Unrealized foreign exchange loss 8 52 ( 1,043 )

Stock-based compensation 6,211 4,281 2,945

Cash settlements paid on exercised stock appreciation rights ( 154 ) ( 378 ) ( 827 )

Derivative instruments (gain) loss, net 745 ( 232 ) 37,812

Derivative instruments loss, net ( 2,876 ) 745 ( 232 )

Cash settlements paid on matured derivative contracts, net ( 48 ) ( 453 ) ( 127 )

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Credit losses and other ( 164 ) 6,346 7,650

Other operating loss, net 34 55 ( 38 )

Equipment and other expensed in operations 5,572 2,505 3,196

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CASH FLOWS FROM INVESTING ACTIVITIES:

Property and equipment expenditures ( 102,996 ) ( 97,223 ) ( 159,897 )

Property and equipment expenditures, including exploration expense ( 252,856 ) ( 102,996 ) ( 97,223 )

Acquisition of crude oil and natural gas properties ( 3,034 ) 877 —

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Proceeds from the issuances of common stock — 447 673

Proceeds from borrowings 60,000 — —

Dividend distribution ( 26,480 ) ( 26,216 ) ( 26,772 )

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Property and equipment additions incurred but not paid at end of period $ 8,190 $ 9,479 $ 14,137

Non-cash consideration exchanged in the acquisition of TransGlobe $ — $ — $ 274,145

Recognition of right-of-use operating lease assets and liabilities $ 3,343 $ 17,649 $ 2,582

Recognition of right-of-use finance lease assets and liabilities $ 2,372 $ — $ 7,875

Reclassification of other long-term assets to right-of-use finance lease assets $ — $ — $ 4,116

Liability awards converted to equity $ — $ — $ 5,336

Asset retirement obligations adjustments $ 85 $ 27,424 $ 2,487

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(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 asset portfolio in Gabon, Egypt, Cote d'Ivoire, Nigeria and Equatorial Guinea, as well as producing properties in Canada.

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.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of consolidation – The accompanying consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries.

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.

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Restricted cash is classified as a current or non-current asset based on its designated purpose and estimated timing of usage.

Current amounts in restricted cash at December 31, 2024 and 2023 each include an escrow amount representing bank guarantees for customs clearance in Gabon.

Long-term amounts at December 31, 2024 and 2023 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note 12 .

Restricted cash also includes a $ 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.

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 the remainder of 2024 .

The remaining balance of the abandonment fund was unchanged during 2025 .

The Company invests restricted and excess cash in readily redeemable money market funds.

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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 – On January 19, 2022 , TransGlobe’s West Gharib, West Bakr and North West Gharib (collectively the “Eastern Desert”) concessions were merged into the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”).

The Merged Concession includes improved cost recovery and production sharing terms scaled to oil prices with a new 15-year development term and a 5-year extension option.

In addition, 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 in connection with the Effective Date Adjustment of $ 67.5 million as of October 2022, based on historical realized prices (the “Backdated Receivable”).

In 2023 and 2024, the Company received payments or provided offsets against the Backdated Receivable.

As of December 31, 2024, the remaining net receivable of $ 33.2 million is recorded in the “Egypt receivables and other” line item on our Consolidated Balance Sheet.

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.

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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 will not be collected.

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 will not be collected.

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

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• Loans to employees.

As a result of adopting ASU 2016-13 on January 1, 2023 , the Company recognized a $ 3.1 million cumulative effect adjustment within retained earnings.

During the year ended December 31, 2023 , the Company reversed $ 12.4 million of credit loss and other allowances due to recoveries from VAT and the Sogara refinery.

During the year ended December 31, 2024, the Company recognized $ 7.7 million in credit loss and other allowances mainly due to amounts owed from EGPC, VAT receivables and receivables from joint venture partners.

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:

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Reversal of allowance resulting from the settlement of the related receivable — 11,200

Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023 — ( 3,120 )

Foreign currency gain — 889

Balance at end of period $ ( 2,652 ) $ ( 2,554 )

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 at December 31, 2024 and the FPSO at December 31, 2023 , but unsold at the end of each period.

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.

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Egypt advances to contractors $ 5,485 $ 3,665

Gabon prepaid royalties 3,089 1,246

Prepaid fixed asset progress payments 3,747 9

Deposits 3,292 2,933

Derivatives 3,053 119

Employee loans and advances 2,398 1,430

Prepaid insurance 650 474

Derivative receivables 119 403

Prepaid fixed asset progress payments 9 2,314

Prepaid royalties 285 3,089

Other prepayments 6,110 3,728

Total prepayments and other $ 24,370 $ 14,973

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

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.

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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.

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.

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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 a valuation allowance is provided if an impairment is indicated.

• 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.

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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.

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The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession.

VAALCO 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 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.

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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.

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.

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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.

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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.

VAALCO uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued.

When VAALCO 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 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.

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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 VAALCO's business plans and investment decisions.

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.

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Derivative asset Prepayments and other $ — $ 3,053 $ — $ 3,053

Derivative asset L-T Other long term assets — 1,209 — 1,209

$ — $ 3,053 $ — $ 3,053

SARs liability Accrued liabilities and other $ — $ — $ — $ —

Derivative liability Accrued liabilities and other $ — $ 207 $ — $ 207

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Derivative asset Prepayments and other $ — $ 119 $ — $ 119

Derivative asset, noncurrent Other long term assets $ — $ 1,209 $ — $ 1,209

$ — $ 1,328 $ — $ 1,328

SARs liability Accrued liabilities and other $ — $ 163 $ — $ 163

Derivative liability Accrued liabilities and other $ — $ 17 $ — $ 17

$ — $ 17 $ — $ 17

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.

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NEW ACCOUNTING STANDARDS

In November 2023, the Financial Accounting Standards Board issued Accounting Standards Update 2023-07, Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures (“ASU 2023-07”).

ASU 2023-07 requires public entities to disclose information about the reportable segments’ significant expenses on an interim and annual basis to enable investors to develop more decision-useful financial analyses.

ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.

Entities must adopt the changes to the segment reporting guidance on a retrospective basis.

We have adopted ASU 2023-07 herein for the fiscal year ended December 31, 2024.

See Note 5, “Segment Information” for our process in determining reportable segments and certain financial data of each segment.

During the fourth quarter of 2024, the Company adopted this ASU, which modified the Company’s disclosures but did not have an impact on the Company’s consolidated balance sheets, or statements of income or cash flows in its consolidated financial statements.

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 August 2023, FASB issued new guidance to provide specific guidance on how a joint venture, upon formation, should recognize and initially measure assets contributed and liabilities assumed.

The rules become effective prospectively for all joint venture formations occurring on or after January 1, 2025.

VAALCO is currently assessing the impact of this guidance on the consolidated financial statements.

In December 2023 , FASB issued new guidance to improve Income Tax disclosures to provide information to assess how an entity’s operations and related tax risks and tax planning and operational opportunities affect its tax rate and prospects for future cash flows.

The rules become effective for annual periods beginning after December 15, 2024 .

The standard modifies required income tax disclosures.

VAALCO is currently evaluating the impact of adopting this guidance on the consolidated financial statements.

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):

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Early adoption is permitted.

VAALCO is currently evaluating the impact of adopting this ASU to our notes to the consolidated financial statements.

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.

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:

Balance Sheet Classification December 31, 2025

(in thousands)

Current assets (Derivative assets, current) Current assets held for sale $ 179

Crude oil, natural gas and NGLs properties and equipment, net

Noncurrent assets held for sale 31,826

Current liabilities (Asset retirement obligation, current) Current liabilities held for sale ( 183 )

Asset retirement obligations Noncurrent liabilities held for sale ( 7,403 )

Net assets held for sale $ 24,419

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 February 29, 2024 , the Company entered into a Share Purchase Agreement (the “Share Purchase Agreement”) to purchase all of the issued shares in the capital of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (“Svenska”) for $ 66.5 million in cash (the “Purchase Price”), subject to certain adjustment as described in the Share Purchase Agreement (the “Svenska Acquisition”).

The Company subsequently closed the Svenska Acquisition for the net purchase price of $ 40.2 million, on April 30, 2024 after certain regulatory and government approvals were received.

The Purchase Price 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 as disclosed within the consolidated statements of cash flows.

The Svenska Acquisition added to the Company’s diversified African-focused asset portfolio.

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.

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.

30 unchanged sentences

Total purchase price $ 40,166 $ — $ 40,166

All assets and liabilities associated with Svenska’s interest in the producing Baobab field as well as the non-producing discovery located offshore of Nigeria, including crude oil and natural gas properties, asset retirement obligations and working capital items, were recorded at their estimated fair value.

The crude oil and natural gas properties and asset retirement obligations were valued using an income approach, which are considered Level 3 fair value estimates.

The Company used estimated future crude oil prices as of the closing date, April 30, 2024, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues.

The future net revenues were discounted using the Company’s weighted average cost of capital to determine the fair value at closing.

The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, and risk adjusted discount rates.

Other estimates were used by the Company to determine the fair value of certain assets and liabilities.

The purchase price allocation was finalized in the fourth quarter of 2024.

As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, a $ 19.9 million bargain purchase gain was recognized as of the close date.

During the year ended December 31, 2024, 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 This adjustment is included in “ Bargain purchase gain ” under “ Other income (expense) ” in the consolidated statements of operations and comprehensive income.

Post-Acquisition Operating Results .

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Net income 12,143

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 years ended December 31, 2024 and 2023 , as if the acquisition had been consummated on January 1, 2023.

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

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Operating income $ 120,681 243,228

Net income (loss) (a)(b)

Net income (a)(b)

$ 38,336 95,740

Basic net income (loss) per share:

Net income (loss) $ 38,336 $ 95,740

Net income (loss) per share $ 0.37 $ 0.90

Basic weighted average shares outstanding 103,669 106,376

Diluted net income (loss) per share:

Net income (loss) $ 38,336 $ 95,740

Net income (loss) per share $ 0.37 $ 0.90

Diluted weighted average shares outstanding 103,747 106,555

(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.

TransGlobe Acquisition

On October 13, 2022 , the Company completed the business combination with TransGlobe Energy Corporation (“TransGlobe”), pursuant to an Arrangement Agreement previously entered into between the Company and TransGlobe (the “Arrangement Agreement”), whereby we acquired all of the issued and outstanding common shares of TransGlobe (the “TransGlobe Acquisition”), for a final adjusted purchase price of $ 274.1 million.

As a result, TransGlobe became a direct wholly-owned subsidiary of the Company.

We recognized an adjusted bargain purchase gain of $ 9.4 million from the transaction based on the difference in the fair value of assets and liabilities assumed and the purchase price and is included in the “Other income (expense), net” in the consolidated statements of operations and comprehensive income.

We acquired our assets in Egypt and Canada through the TransGlobe Acquisition.

For the year ended December 31, 2022 , included in the line item “Other income (expense), net” is $ 14.6 million of transactions costs associated with the TransGlobe Acquisition.

The unaudited pro forma results presented below have been prepared to give the effect to the TransGlobe Acquisition discussed above on the Company’s results of operations for the years ended December 31, 2022 , as if the TransGlobe Acquisition had been consummated on January 1, 2021.

The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the TransGlobe Acquisition had been completed on such date or to project the Company’s results of operations for any future date or period.

Year Ended December 31, 2022 Measurement Period

Adjustment Year Ended December 31, 2022

(As Adjusted)

(in thousands)

Pro forma (unaudited):

Crude oil, natural gas and natural gas liquids sales $ 547,670 (a) $ — $ 547,670 (a)

Operating income $ 267,582 (b) $ — $ 267,582 (b)

Net income $ 130,425 (c) $ 1,412 (d) $ 131,837 (c)

Basic net income per share:

$ 1.21 $ 0.01 (d) $ 1.22

Net income $ 38,336 $ 95,740

Net income per share $ 0.37 $ 0.90

Basic weighted average shares outstanding 103,669 106,376

Diluted net income per share:

$ 1.20 $ 0.01 (d) $ 1.21

Net income $ 38,336 $ 95,740

Net income per share $ 0.37 $ 0.90

Diluted weighted average shares outstanding 103,747 106,555

(a) The unaudited pro forma net revenues associated with Crude oil, natural gas and natural gas liquids sales have been adjusted for shipping and handling costs based on the Company’s historical policy and revenue recognition is based on the Company’s working interest, less royalties, the entitlement method.

(b) The unaudited pro forma operating income for the year ended December 31, 2022 removes the $ 23.7 million impairment reversal recorded by TransGlobe in 2022, excludes $ 10.2 million of severance costs associated with the TransGlobe Acquisition, excludes $ 6.5 million of TransGlobe Acquisition transaction costs, reclassifies depreciation expense, for certain leases identified as operating leases, to production expense and adjusts depreciation, depletion and amortization expense related to the depletable assets and asset retirement obligations acquired in the TransGlobe Acquisition based on the purchase price allocation.

(c) The unaudited pro forma net income for the year ended December 31, 2022 excludes $ 14.6 million of transaction costs incurred by the Company associated with the TransGlobe Acquisition, excludes the bargain purchase gain of $ 10.8 million and reclassifies interest expense, for certain leases identified as operating leases, as production expense.

(d) The Measurement Period Adjustment is due to an original deferred tax liability being estimated at closing.

Additional information about the deferred tax liability was identified in the first part of 2023 creating the need for the $ 1.4 million adjustment.

SEGMENT INFORMATION

The Company’s operations are based in Gabon, Egypt, Cote d'Ivoire, Canada and Equatorial Guinea.

Each of the reportable 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, 2024 , 2023 and 2022 and long-lived assets and segment assets at December 31, 2024 and 2023 are as follows:

Year ended December 31, 2024

(in thousands) Gabon Egypt Canada Equatorial Guinea Cote d'Ivoire Corporate and Other Total

Crude oil, natural gas and natural gas liquids sales $ 205,954 $ 145,966 $ 31,986 $ — $ 95,082 $ — $ 478,988

Operating costs and expenses:

Production expense 62,234 50,770 11,301 1,173 38,017 5 163,500

Exploration expense — 48 — — — — 48

Depreciation, depletion and amortization 50,679 33,458 19,309 — 38,771 817 143,034

General and administrative expense 1,679 70 ( 206 ) 305 1,701 26,135 29,684

Credit (recovery) losses and other 812 4,813 — 679 — — 6,304

Total operating costs and expenses 115,404 89,159 30,404 2,157 78,489 26,957 342,570

Other operating income (expense), net ( 24 ) — 102 — — — 78

Operating income (loss) 90,526 56,807 1,684 ( 2,157 ) 16,593 ( 26,957 ) 136,496

Other income (expense):

Derivative instruments gain (loss), net — — — — ( 533 ) ( 212 ) ( 745 )

Interest (expense) income, net ( 4,694 ) ( 1,489 ) ( 46 ) — 313 2,184 ( 3,732 )

Bargain purchase gain — — — — — 13,532 13,532

Other income (expense), net ( 1,635 ) ( 204 ) 225 ( 7 ) ( 1 ) ( 4,132 ) ( 5,754 )

Total other income (expense), net ( 6,329 ) ( 1,693 ) 179 ( 7 ) ( 221 ) 11,372 3,301

Income (loss) before income taxes 84,197 55,114 1,863 ( 2,164 ) 16,372 ( 15,585 ) 139,797

Income tax expense 48,026 30,648 — — 4,229 ( 1,596 ) 81,307

Net income (loss) $ 36,171 $ 24,466 $ 1,863 $ ( 2,164 ) $ 12,143 $ ( 13,989 ) $ 58,490

Consolidated capital expenditures $ 22,579 $ 11,364 $ 25,828 $ 641 $ 44,435 $ 4,592 $ 109,438

Year Ended December 31, 2023

(in thousands) Gabon Egypt Canada Equatorial Guinea Corporate and Other Total

Crude oil, natural gas and natural gas liquids sales $ 260,346 $ 161,049 $ 33,671 $ — $ — $ 455,066

Operating costs and expenses:

Production expense 87,131 54,779 9,463 1,481 303 153,157

FPSO demobilization and other costs 7,484 — — — — 7,484

Exploration expense 51 1,914 — — — 1,965

Depreciation, depletion and amortization 62,622 35,095 17,398 — 187 115,302

General and administrative expense 1,769 974 — 416 20,681 23,840

Credit (recovery) losses and other ( 10,596 ) 5,182 — 508 — ( 4,906 )

Total operating costs and expenses 148,461 97,944 26,861 2,405 21,171 296,842

Other operating income (expense), net ( 55 ) ( 241 ) 729 — — 433

Operating income (loss) 111,830 62,864 7,539 ( 2,405 ) ( 21,171 ) 158,657

Other income (expense):

Derivative instruments gain (loss), net — — — — 232 232

Interest (expense) income, net ( 5,563 ) ( 2,110 ) ( 4 ) — 1,225 ( 6,452 )

Other expense, net ( 820 ) — 2 ( 6 ) ( 1,482 ) ( 2,306 )

Total other income (expense), net ( 6,383 ) ( 2,110 ) ( 2 ) ( 6 ) ( 25 ) ( 8,526 )

Income (loss) before income taxes 105,447 60,754 7,537 ( 2,411 ) ( 21,196 ) 150,131

Income tax (benefit) expense 50,692 32,859 - — 6,226 89,777

Net income (loss) $ 54,755 $ 27,895 7,537 ( 2,411 ) $ ( 27,422 ) $ 60,354

Consolidated capital expenditures (1)

$ 17,011 $ 37,866 16,809 — $ 950 $ 72,636

(1) Includes assets acquired in the TransGlobe acquisition.

Year Ended December 31, 2022

(in thousands) Gabon Egypt Canada Equatorial Guinea Corporate and Other Total

Crude oil, natural gas and natural gas liquids sales $ 306,775 $ 37,710 $ 9,841 $ — $ — $ 354,326

Operating costs and expenses:

Production expense 96,854 11,936 1,972 1,899 — 112,661

FPSO demobilization and other costs 8,867 — — — — 8,867

Exploration expense 258 — — — — 258

Depreciation, depletion and amortization 34,651 10,444 2,921 — 127 48,143

General and administrative expense 3,101 — — 538 6,438 10,077

Credit (recovery) losses and other 2,743 — — 339 — 3,082

Total operating costs and expenses 146,474 22,380 4,893 2,776 6,565 183,088

Other operating income (expense), net 38 — — — — 38

Operating income (loss) 160,339 15,330 4,948 ( 2,776 ) ( 6,565 ) 171,276

Other income (expense):

Derivative instruments loss, net — — 13 — ( 37,825 ) ( 37,812 )

Interest income, net ( 1,446 ) ( 596 ) — — 8 ( 2,034 )

Other income (expense), net ( 1,484 ) — — — ( 6,636 ) ( 8,120 )

Total other income (expense), net ( 2,930 ) ( 596 ) 13 — ( 44,453 ) ( 47,966 )

Income (loss) before income taxes 157,409 14,734 4,961 ( 2,776 ) ( 51,018 ) 123,310

Income tax (benefit) expense 68,509 6,254 — 1 ( 3,344 ) 71,420

Net income (loss) $ 88,900 $ 8,480 $ 4,961 $ ( 2,777 ) $ ( 47,674 ) $ 51,890

Consolidated capital expenditures $ 162,375 $ 168,012 $ 103,263 $ — $ 710 $ 434,360

(in thousands) Gabon Egypt Canada Equatorial Guinea Cote d'Ivoire Corporate and Other Total

Long-lived assets:

As of December 31, 2024 $ 153,576 $ 149,129 $ 104,891 $ 10,641 $ 114,756 $ 5,110 $ 538,103

As of December 31, 2023 $ 171,787 $ 171,224 $ 105,189 $ 10,000 $ — $ 1,586 $ 459,786

(in thousands) Gabon Egypt Canada Equatorial Guinea Cote d'Ivoire Corporate and Other Total

Total assets:

As of December 31, 2024 $ 300,568 $ 269,905 $ 113,310 $ 12,331 $ 187,264 $ 71,572 $ 954,950

As of December 31, 2023 $ 309,394 $ 263,015 $ 114,215 $ 11,327 $ — $ 125,265 $ 823,216

EARNINGS PER SHARE

5 unchanged sentences

(in thousands)

Net income (numerator):

Net income $ 58,490 $ 60,354 $ 51,890

Net income (loss) (numerator):

Net income (loss) $ ( 41,391 ) $ 58,490 $ 60,354

Income attributable to unvested shares ( 475 ) ( 714 ) ( 632 )

Numerator for basic ( 41,866 ) 57,776 59,722

Loss attributable to unvested shares — 1 3

Income attributable to unvested shares — — 1

Numerator for dilutive $ ( 41,866 ) $ 57,776 $ 59,723

3 unchanged sentences

Diluted weighted average shares outstanding 104,055 103,747 106,555

Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive 516 385 189

Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be antidilutive 3,608 516 385

Production Sharing Contracts

14 unchanged sentences

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.

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.

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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.

In 2024 , an in-kind payment of $ 30.3 million was made with the May 2024 lifting.

The Company has a $ 40.0 foreign income tax payable as of December 31, 2024.

In the prior year, an in-kind payment of $ 32.8 million was made with the November 2023 lifting.

As of December 31, 2023, there was a foreign income tax payable of $ 18.9 million.

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.

2 unchanged sentences

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

Year Ended December 31,

2025 2024 2023

2 unchanged sentences

Sales under the COSPA or COSMA $ 176,508 $ 205,965 $ 261,801

Other items reported in revenue not associated with customer contracts:

Gabonese government share of Profit Oil taken in-kind 31,845 30,256 32,776

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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 for reporting purposes.

EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC cooperation and approval to schedule liftings.

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.

Direct sales to EGPC are normally settled two to four weeks from delivery.

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 over lift or underlift position, sales are based on the Company’s working interest, less royalties.

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.

8 unchanged sentences

Net revenues $ 139,963 $ 145,966 $ 161,049

Customer sales generally occur on a daily basis when crude oil, natural gas, condensate or NGL’s are 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.

VAALCO pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime.

For reporting purposes, the Company records revenues net of royalties.

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

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.

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:

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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”).

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

Production generated fr om 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.

18 unchanged sentences

Sales under the sales and purchase agreements $ 16,528 $ 87,870

Other item reported in revenue not associated with customer contracts:

Cote d’Ivoire government share of Profit Oil taken in-kind 1,869 7,212

11 unchanged sentences

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

(2) For Egypt and Canada, reflects sales from October 14, 2022 through December 31, 2022 related to the TransGlobe Acquisition.

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

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(in thousands) 2025

Tax provision computed at U.S.

statutory rate $ 29,360 $ 31,530 $ 25,910

Foreign taxes not offset in U.S.

by foreign tax credits 14,833 25,719 53,851

Permanent differences 932 3,455 778

Foreign tax credit expirations — — 17,247

Increase/(decrease) in valuation allowance 34,281 27,656 ( 25,623 )

Bargain purchase gain ( 2,842 ) — —

Other 4,743 1,417 ( 743 )

Total income tax expense (benefit) $ 81,307 $ 89,777 $ 71,420

Federal Statutory Tax Rate $ ( 5,580 ) 21.00 %

Domestic Federal

Tax Credits - Foreign Tax Credit ( 13,982 ) 52.63 %

Changes in Valuation Allowance 7,385 ( 27.79 ) %

Cross-border tax laws - US taxation of foreign disregarded entity 8,242 ( 31.02 ) %

Nontaxable or nondeductible items 806 ( 3.03 ) %

Foreign Tax Effects

Statutory income tax rate differential 4,923 ( 18.53 ) %

Rate difference between Gabon statutory tax rate and the PSC 9,435 ( 35.51 ) %

Nontaxable or nondeductible items:

Non Recoverable Costs 1,067 ( 4.02 ) %

Nondeductible Interest 1,670 ( 6.29 ) %

Impact of revenue differences between production and lifting ( 8,075 ) 30.39 %

Carried interests ( 1,020 ) 3.84 %

Other reconciling items 478 ( 1.80 ) %

Changes in Valuation Allowance 2,095 ( 7.89 ) %

Statutory income tax rate differential 9,067 ( 34.13 ) %

Nontaxable or nondeductible items:

Non Recoverable Costs 2,288 ( 8.61 ) %

Other reconciling items ( 92 ) 0.35 %

Changes in Valuation Allowance 356 ( 1.34 ) %

Statutory income tax rate differential 4,184 ( 15.75 ) %

Subnational income taxes ( 5,580 ) 21.00 %

Changes in Valuation Allowance 16,045 ( 60.39 ) %

Cote D'Ivoire

Statutory income tax rate differential ( 716 ) 2.70 %

Rate difference between statutory tax rate and the PSC ( 12,197 ) 45.91 %

Nontaxable or nondeductible items:

Non Recoverable Costs 1,033 ( 3.89 ) %

Stat to US GAAP adjustments ( 1,250 ) 4.71 %

Cost Recovery Uplift ( 9,167 ) 34.50 %

Changes in Valuation Allowance 1,834 ( 6.90 ) %

Equatorial Guinea

Statutory income tax rate differential ( 119 ) 0.45 %

Changes in Valuation Allowance 744 ( 2.80 ) %

Tax Credits - Foreign Tax Credit ( 3,767 ) 14.18 %

Cross-border tax laws - Sweden taxation of foreign disregarded entity ( 2,885 ) 10.86 %

Nontaxable or nondeductible items:

Realized foreign exchange gain 4,036 ( 15.19 ) %

Other reconciling items ( 100 ) 0.38 %

Changes in Valuation Allowance 3,126 ( 11.76 ) %

Nontaxable or nondeductible items:

Other reconciling items 538 ( 2.03 ) %

Total $ 14,822 ( 55.77 ) %

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

(in thousands)

$ 36,739 $ 31,109

29,025 31,355

Cote d’Ivoire

Total taxes paid

$ 67,985 $ 71,619

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.

8 unchanged sentences

Fixed assets (1)

$ 40,988 $ 35,541

Foreign tax credit carryforward 133,803 123,660

20 unchanged sentences

Expiration Period

$ — No expiration

Gabon $ — No expiration

Egypt $ 14,596 2026-2028

1 unchanged sentence

Equatorial Guinea $ 127,564 No expiration

UK $ — No expiration

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.

2 unchanged sentences

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.

8 unchanged sentences

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, 2024 and 2023 , respectively, is comprised of the following:

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

(in thousands)

8 unchanged sentences

Unproved property costs

See the table below for the list of unproved property costs at December 31, 2024 and 2023 , respectively:

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

(in thousands)

Unproved Property Costs

Etame Marin Block $ 13,735 $ 13,735

Gabon 15,235 $ 13,735

Equatorial Guinea 10,000 10,000

3 unchanged sentences

Unproved Property Costs $ 52,079 $ 60,761

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 2024, we had minimal exploration expenses.

During 2023 , two appraisal wells, both in Egypt, were abandoned and also expensed to Exploration Expense.

The impact resulted in $ 2.0 million of expense during the year ended December 31, 2023 .

DERIVATIVES AND FAIR VALUE

Commodity swaps

Outstanding derivative contracts at December 31, 2024 are as follows:

Settlement Period Type of Contract Index Average Monthly Volumes Weighted Average Put Price Weighted Average Call Price

(per Bbl) (per Bbl)

January 2025 - March 2025 Collars Dated Brent 70,000 $ 65.00 $ 85.00

April 2025 - June 2025 Collars Dated Brent 70,000 $ 65.00 $ 81.00

Settlement Period Type of Contract Index Average Monthly Volumes Weighted Average SWAP Price in CAD

January 2025 - March 2025 Swap AECO (7A) 67,000 $ 2.80

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.

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:

Settlement Period

Instrument Index January 2026 - March 2026 April 2026 - June 2026 July 2026 - September 2026 October 2026 - December 2026

Collars Dated Brent

Total volumes (Bbls) 400,000 360,000 75,000 —

Weighted average floor price ($/Bbl) $ 62.29 $ 61.88 $ 65.00 $ —

Weighted average ceiling price ($/Bbl) $ 68.63 $ 67.95 $ 71.00 $ —

Natural Gas (a) :

Swaps AECO 7A

Total volumes (GJs) (b)

225,000 150,000 150,000 50,000

Weighted average fixed price (CAD/GJ) $ 2.99 $ 2.80 $ 2.80 $ 2.80

(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 about 25.5 cubic metres at standard conditions.

A gigajoule of natural gas is approximately 25.5 cubic meters standard conditions.

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):

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(in thousands) 2025 2024

Asset retirement obligation $ 47,343 $ 42,001

Beginning balance $ 79,766 $ 47,343

Accretion 6,364 4,753

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Settlements ( 225 ) ( 368 )

Foreign currency gain (loss) ( 367 ) 361

Total asset retirement obligation 79,766 47,343

Liabilities classified as held for sale ( 7,586 ) —

Foreign currency loss ( 342 ) ( 367 )

Ending balance 78,406 79,766

current obligations — ( 1,174 )

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The amounts paid will be reimbursed through the Cost Account and are non-refundable.

In August 2023 , a new abandonment study was completed and such study estimated abandonment costs of approximately $ 77.9 million ($ 45.9 million, net to VAALCO) on an undiscounted basis.

The new abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the PSC.

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.

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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 during the remainder of 2023 and in 2024.

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.

As operator of the Etame Marin block, the Company chartered a floating production storage and offtake vessel (“FPSO”), from Tinworth for use in its operations.

In the fourth quarter of 2023 , the Company reached a settlement agreement with Tinworth to release the Company from any further obligation relating to the FPSO.

The signed settlement agreement required the Company and other non-operators to pay an additional $ 8.0 million gross ($ 4.7 million net to VAALCO) to Tinworth in exchange for the release.

The $ 8.0 million payment was made on December 22, 2023 .

In connection with the above settlement, on January 22, 2024 , certain funds held in escrow as part of the FPSO agreements were released to the Company and its non-operating partners.

VAALCO's share of this restricted cash amount was $ 1.8 million.

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

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

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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 are required to make $ 10.0 million annual modernization payments through February 1, 2026 .

The $ 10.0 million modernization payment due February 1, 2024 , was offset against receivables owed to the Company from EGPC.

On the consolidated balance sheet, $ 9.9 million of the modernization payment liability was recorded in the line item "Accrued liabilities and other" and $ 9.2 million was recorded in “Other long-term liabilities”.

In accordance with the Merged Concession Agreement, we agreed to substitute the 2023 and 2024 payment and issue two $ 10.0 million credits against receivables owed from 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.

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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.

As of December 31, 2024 and 2023, the Company had no outstanding debt.

On May 16, 2022 , the Company entered into an agreement with Glencore, and other lenders, to provide a senior secured reserve-based revolving credit facility for a maximum principal amount of up to $ 50.0 million.

Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the RBL Facility, the $ 50.0 million initial

commitment, will be reduced by $ 6.3 million.

At December 31, 2024 , the amount available to be drawn under the facility was $ 31.3 million.

The Facility provides for determination of the borrowing base asset based on the Company’s proved producing reserves in Gabon and a portion of the Company's proved undeveloped reserves in Gabon.

The borrowing base is re-determined by the Glencore and other lenders on March 31 and September 30 of each year.

The RBL Facility originally bore an interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00 % until the third anniversary of the Facility Agreement or (ii) 6.25 % from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).

On October 3, 2023 the Company signed an Amended and Restated Facility Agreement to replace the LIBOR component, in the original Facility Agreement, with a SOFR plus credit adjustment spread rate.

The SOFR plus credit adjustment spread rate is intended to approximate the LIBOR component in the original Facility Agreement and the LIBOR component was replaced due to LIBOR being discontinued as a global reference rate.

Pursuant to the RBL Facility agreement, the Company shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35 % per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20 % per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount.

The Company is also required to pay customary arrangement and security agent fees.

The RBL Facility agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the RBL Facility agreement) for the trailing 12 months shall not exceed 3.0 x and (ii) consolidated cash and cash equivalents shall not be lower than $ 10.0 million at any time.

The amount the Company can borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the RBL Facility agreement.

Regarding the requirement, the Company must deliver its annual financial statements to Glencore within 90 days of the end of each fiscal year.

At December 31, 2024 , the Company was in compliance with all other debt covenants and had no outstanding borrowings under the facility.

The RBL Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the RBL Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the RBL Facility agreement).

On March 4, 2025, the Company and certain of its subsidiaries, 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 aggregate commitments of $ 190.0 million and an initial borrowing base of $ 182.0 million.

Subsequent Events for additional discussion on the terms of the 2025 Facility Agreement.

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.

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 were no 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.

Under the leasing standard that became effective January 1, 2019 , there are two types of leases:

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Operating leases

The Company is currently a party to two operating lease agreements for the corporate office and transportation equipment.

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.

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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.

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 13 to 93 months.

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.

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.

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Finance lease cost (1) :

$ 19,198 $ 17,297 $ 3,682

Amortization of lease assets $ 13,558 $ 12,924 $ 10,253

Interest on lease liabilities 5,449 6,274 7,044

Operating lease cost 5,018 5,100 1,403

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Other information:

(in thousands)

Cash paid for amounts included in the measurement of lease liabilities:

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Total lease liabilities $ 16,927 $ 69,375

Under the joint operating agreements, other joint venture owners are obligated to fund $ 49.2 million of the $ 121.8 million in future lease liabilities as of December 31, 2024.

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.

ACCRUED LIABILITIES AND OTHER

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State oil liability 18,244 19,616

Capital expenditures 8,923 10,136

Egypt modernization payments 9,933 9,933

Accrued capital expenditures 51,339 8,923

Egypt modernization payable — 9,933

Gabon contractual obligations 3,858 6,977

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Other 8,834 4,763

Total accrued liabilities and other $ 107,710 $ 67,597

Total accrued liabilities and other (a)

$ 106,444 $ 107,710

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

SHAREHOLDERS ’ EQUITY

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Dividend Payment Date Amount per common share Record Date

March 28, 2024 $ 0.0625 March 8, 2024

March 28, 2025 $ 0.0625 February 28, 2025

June 27, 2025 $ 0.0625 May 23, 2025

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Treasury stock

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 provides 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 will be funded using the Company's cash on hand and cash flow from operations.

The below table shows the repurchases of equity securities related to the share repurchase program during the fiscal year ended December 31, 2024.

The share buyback program was completed on March 12, 2024.

Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Programs Maximum Amount that May Yet Be Used to Purchase Shares Under the Program

January 1, 2024 - January 31, 2024 446,366 $ 4.48 446,366 $ 3,516,205

February 1, 2024 - February 29, 2024 474,100 $ 4.22 474,100 $ 1,516,630

March 1, 2024 - March 12, 2024 347,137 $ 4.33 347,137 $ —

Total 1,267,603 1,267,603

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

Commitments and Contingencies.

STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS

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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 , 2023 and 2022, the Company settled in cash $ 0.2 million, $ 0.4 million and $ 0.8 million, respectively, for SARs.

During the years ended December 31, 2024 , 2023 and 2022, the Company received in cash $ 0.4 million, $ 0.7 million and $ 0.3 million, respectively from stock option exercises.

During the years ended December 31, 2024 and 2023, the Company settled in cash $ 0.2 million and $ 0.4 million, respectively, for SARs no 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.

Year Ended December 31,

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Total stock-based compensation $ 5,954 $ 4,558 $ 3,323

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 of three 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.

Year Ended December 31,

Average expected volatility 68.71 %

Risk-free interest rate 4.40 %

Expected dividend yield 7.44 %

Weighted average grant date fair value - ($/share) $ 2.29

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

Number of Shares Underlying Options Weighted Average Exercise Price Per

Share Weighted Average Remaining

Contractual Term

(in thousands) (in years)

Unvested at January 1, 2025 — $ —

Granted 790 2.29

Unvested at December 31, 2025 790 $ 2.29 1.75

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

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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 of ten years .

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.

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 were no 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.

Year Ended December 31,

2024 2023 2022

Weighted average exercise price - ($/share) $ 5.96 $ 4.19

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Outstanding at January 1, 2025 1,118 $ 5.32

Granted 549 5.96

Exercised ( 24 ) 4.54

Unvested shares forfeited ( 21 ) 6.41

Vested shares expired — —

Outstanding at December 31, 2025 1,097 $ 5.30 7.6 $ 79

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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.

The intrinsic performance stock option awards exercised in 2024 was $ 43.1 thousand.

As of December 31, 2024 , unrecognized compensation cost related to outstanding performance stock option awards was $ 1.6 million, which is expected to be recognized over a weighted average period of two years .

Regular stock options (stock options without a performance condition) activity associated with the Black-Scholes model for the year ended December 31, 2024 is provided below:

Number of Shares Underlying Options Weighted Average Exercise Price Per Share

(in thousands)

Outstanding at January 1, 2024 170 $ 1.99

Exercised ( 170 ) 1.99

Outstanding at December 31, 2024 — $ —

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, 2023 and 2022 was $ 0.5 million, $ 0.6 million, and $ 1.2 million, respectively.

There was no unrecognized stock compensation cost as of December 31, 2024 and December 31, 2023 , respectively.

During the year ended December 31, 2024, 72,864 shares were added to treasury as a result of tax withholding on the stock option awards exercised.

The intrinsic value of stock options exercised in 2024 and 2023 was $ 0.5 million and $ 0.6 million, respectively.

Restricted shares

11 unchanged sentences

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, 2024, 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 two years .

In connection with the TransGlobe Acquisition and pursuant to the Arrangement Agreement, at the effective time of the TransGlobe Acquisition, certain awards previously issued to TransGlobe’s key employees and board members who continued their relationship as employees or board members of the Company following the TransGlobe Acquisition, will continue to be governed by the applicable TransGlobe plan, provided that each such applicable plan has been amended to provide that the Company common stock shall be issuable in lieu of cash or TransGlobe common stock with respect to TransGlobe’s deferred share units (“DSU”s), performance share units (“PSU”s) and restricted stock units (“RSU”s), in each case, based on the exchange ratio in the Arrangement Agreement.

For the PSUs that will remain outstanding following the effective time of the TransGlobe Acquisition as described in the immediately preceding sentence, the

applicable vesting percentage was determined by the TransGlobe board of directors to be 200 % for PSUs granted in 2021 and 2022;

and 64.4 % for PSUs granted in 2023 .

As of October 13, 2022, the effective date of the TransGlobe Acquisition, the combined fair value of the DSUs, PSU's and RSU's liability from TransGlobe was $ 6.0 million.

On December 16, 2022 , the Compensation Committee determined that the awards would be settled in shares from the 2021 Plan, thereby converting all the awards from cash-settled liability awards to equity awards.

On the date of this conversion, the awards were revalued based on the Company’s share price, and the Company recognized a gain of $ 0.6 million in its consolidated statements of operations and comprehensive income (loss).

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 a three-year period.

On December 16, 2022 , the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards.

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

8 unchanged sentences

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

As of December 31, 2024, unrecognized compensation cost related to RSU’s totaled $ 1.3 million and is expected to be recognized over a weighted average period of 0.5 years.

During the year ended December 31, 2024, 30,189 shares were added to treasury as a result of tax withholding on the vesting of RSU’s.

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.

2 unchanged sentences

All PSUs granted vest on the third anniversary of their grant date.

On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards.

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

2 unchanged sentences

Non-vested shares outstanding at January 1, 2025 9 $ 4.27

Awards granted — —

Awards vested ( 9 ) 4.27

Awards forfeited ( 9 ) 4.27

Non-vested shares outstanding at December 31, 2025 — $ —

As of December 31, 2024, unrecognized compensation cost related to PSU’s totaled $ 0.00 million .

During the year ended December 31, 2024, 19,742 shares were added to treasury as a result of tax withholding on the vesting of PSU’s.

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.

On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards.

At December 31, 2025 , there are approximately 101,313 DSUs outstanding, which are vested but not converted.

5 unchanged sentences

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.

During the years ended December 31, 2024 and 2023, the Company did not grant SARs to employees or directors.

SAR activity for the year ended December 31, 2024 is provided below:

Number of Shares Underlying SARs Weighted Average Exercise Price Per

(in thousands)

Outstanding at January 1, 2024 76 $ 2.33

Exercised ( 76 ) 2.33

Outstanding at December 31, 2024 —

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 , 2023 and 2022 was $ 0.2 million, $ 0.4 million, and 0.8 million respectively.

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 did not 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 its named executive officers and certain other officers of the Company as well as a severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control.

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 and participants in the severance plan 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.

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.

2 unchanged sentences

VAALCO has entered into various agreements with related parties.

The Company paid approximately $ 0.2 million to these related parties for each of the years ended December 31, 2024 and 2023 , respectively.

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.

OTHER COMPREHENSIVE INCOME

OTHER COMPREHENSIVE INCOME (LOSS)

At December 31, 2025 , the Company’s accumulated other comprehensive loss was $ 0.5 million.

4 unchanged sentences

Balance at December 31, 2023 $ 2,880

Amounts reclassified from accumulated other comprehensive income (loss) 1,701

Amounts reclassified from accumulated other comprehensive loss ( 7,842 )

Balance at December 30, 2024 $ ( 4,962 )

Amounts reclassified from accumulated other comprehensive income (loss) ( 7,842 )

Amounts reclassified from accumulated other comprehensive income 4,464

Balance at December 31, 2025 $ ( 498 )

SEGMENT INFORMATION

The Company’s operations are based in Gabon, Egypt, Cote d'Ivoire, Canada and Equatorial Guinea.

Each of the reportable operating segments are organized and managed based upon geographic location.

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.

No transactions occurred between operating segments.

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:

Year Ended December 31, 2025

(in thousands) Gabon Egypt Canada Equatorial Guinea Cote d'Ivoire Corporate and Other Total

Crude oil, natural gas and natural gas liquids sales $ 181,738 $ 139,963 $ 19,174 $ — $ 18,397 $ — $ 359,272

Operating costs and expenses:

Production expense 84,677 53,539 8,458 1,561 9,941 1 158,177

Exploration expense 3,799 2,409 — — 2,706 — 8,914

Depreciation, depletion and amortization 48,739 36,649 13,485 — 10,134 971 109,978

Impairment loss on assets held for sale — — 67,224 — — — 67,224

General and administrative expense 1,684 545 136 282 2,138 28,304 33,089

Credit (recovery) losses and other ( 792 ) ( 228 ) — 1,126 — — 106

Total operating costs and expenses 138,107 92,914 89,303 2,969 24,919 29,276 377,488

Other operating income (expense), net 18 — — — ( 2,409 ) — ( 2,391 )

Operating income (loss) 43,649 47,049 ( 70,129 ) ( 2,969 ) ( 8,931 ) ( 29,276 ) ( 20,607 )

Other income (expense):

Derivative instruments loss, net — — — — — 2,876 2,876

Interest expense, net ( 3,443 ) ( 862 ) — — ( 3,117 ) ( 821 ) ( 8,243 )

Bargain purchase gain — — — — — — —

Other income (expense), net ( 1,096 ) 155 444 ( 5 ) 325 ( 418 ) ( 595 )

Total other income (expense), net ( 4,539 ) ( 707 ) 444 ( 5 ) ( 2,792 ) 1,637 ( 5,962 )

Income (loss) before income taxes 39,110 46,342 ( 69,685 ) ( 2,974 ) ( 11,723 ) ( 27,639 ) ( 26,569 )

Income tax (benefit) expense 17,959 21,358 — — ( 22,631 ) ( 1,864 ) 14,822

Net income (loss) $ 21,151 $ 24,984 $ ( 69,685 ) $ ( 2,974 ) $ 10,908 $ ( 25,775 ) $ ( 41,391 )

Consolidated capital expenditures $ 61,739 $ 28,768 $ 1,588 $ 607 $ 143,186 $ 526 $ 236,414

Year Ended December 31, 2024

(in thousands) Gabon Egypt Canada Equatorial Guinea Côte d'Ivoire Corporate and Other Total

Crude oil, natural gas and natural gas liquids sales $ 205,954 $ 145,966 $ 31,986 $ — $ 95,082 $ — $ 478,988

Operating costs and expenses:

Production expense 62,234 50,770 11,301 1,173 38,017 5 163,500

Exploration expense — 48 — — — — 48

Depreciation, depletion and amortization 50,679 33,458 19,309 — 38,771 817 143,034

General and administrative expense 1,679 70 ( 206 ) 305 1,701 26,135 29,684

Credit (recovery) losses and other 812 4,813 — 679 — — 6,304

Total operating costs and expenses 115,404 89,159 30,404 2,157 78,489 26,957 342,570

Other operating income (expense), net ( 24 ) — 102 — — — 78

Operating income (loss) 90,526 56,807 1,684 ( 2,157 ) 16,593 ( 26,957 ) 136,496

Other income (expense):

Derivative instruments gain (loss), net — — — — ( 533 ) ( 212 ) ( 745 )

Interest (expense) income, net ( 4,694 ) ( 1,489 ) ( 46 ) — 313 2,184 ( 3,732 )

Bargain Purchase Gain — — — — — 13,532 13,532

Other income (expense), net ( 1,635 ) ( 204 ) 225 ( 7 ) ( 1 ) ( 4,132 ) ( 5,754 )

Total other income (expense), net ( 6,329 ) ( 1,693 ) 179 ( 7 ) ( 221 ) 11,372 3,301

Income (loss) before income taxes 84,197 55,114 1,863 ( 2,164 ) 16,372 ( 15,585 ) 139,797

Income tax (benefit) expense 48,026 30,648 — — 4,229 ( 1,596 ) 81,307

Net income (loss) $ 36,171 $ 24,466 $ 1,863 $ ( 2,164 ) $ 12,143 $ ( 13,989 ) $ 58,490

Consolidated capital expenditures $ 22,579 $ 11,364 $ 25,828 $ 641 $ 44,435 $ 4,592 $ 109,439

Year Ended December 31, 2023

(in thousands) Gabon Egypt Canada Equatorial Guinea Corporate and Other Total

Crude oil, natural gas and natural gas liquids sales $ 260,346 $ 161,049 $ 33,671 $ — $ — $ 455,066

Operating costs and expenses:

Production expense 87,131 54,779 9,463 1,481 303 153,157

FPSO demobilization and other costs 7,484 — — — — 7,484

Exploration expense 51 1,914 — — — 1,965

Depreciation, depletion and amortization 62,622 35,095 17,398 — 187 115,302

General and administrative expense 1,769 974 — 416 20,681 23,840

Credit (recovery) losses and other ( 10,596 ) 5,182 — 508 — ( 4,906 )

Total operating costs and expenses 148,461 97,944 26,861 2,405 21,171 296,842

Other operating income (expense), net ( 55 ) ( 241 ) 729 — — 433

Operating income (loss) 111,830 62,864 7,539 ( 2,405 ) ( 21,171 ) 158,657

Other income (expense):

Derivative instruments loss, net — — — — 232 232

Interest income, net ( 5,563 ) ( 2,110 ) ( 4 ) — 1,225 ( 6,452 )

Bargain purchase gain measurement period adjustment — — — — ( 1,412 ) ( 1,412 )

Other income (expense), net ( 820 ) — 2 ( 6 ) ( 70 ) ( 894 )

Total other income (expense), net ( 6,383 ) ( 2,110 ) ( 2 ) ( 6 ) ( 25 ) ( 8,526 )

Income (loss) before income taxes 105,447 60,754 7,537 ( 2,411 ) ( 21,196 ) 150,131

Income tax (benefit) expense 50,692 32,859 — — 6,226 89,777

Net income (loss) $ 54,755 $ 27,895 $ 7,537 $ ( 2,411 ) $ ( 27,422 ) $ 60,354

Consolidated capital expenditures $ 17,011 $ 37,866 $ 16,809 $ — $ 950 $ 72,636

(in thousands) Gabon Egypt Canada (a)

Equatorial Guinea Côte d'Ivoire Corporate and Other Total

Long-lived assets:

As of December 31, 2025 $ 177,030 $ 138,839 $ — $ 11,248 $ 254,307 $ 4,671 $ 586,095

As of December 31, 2024 $ 153,576 $ 149,129 $ 104,891 $ 10,641 $ 114,756 $ 5,110 $ 538,103

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

(in thousands) Gabon Egypt Canada Equatorial Guinea Côte d'Ivoire Corporate and Other Total

Total assets:

As of December 31, 2025 $ 315,787 $ 182,023 $ 35,982 $ 13,631 $ 283,768 $ 82,184 $ 913,375

As of December 31, 2024 $ 300,568 $ 269,905 $ 113,310 $ 12,331 $ 187,264 $ 71,572 $ 954,950

SUBSEQUENT EVENTS

2025 RBL Facility

On March 4, 2025, the Company and certain of its subsidiaries, entered into the 2025 Facility Agreement with The Standard Bank of South Africa Limited, Isle of Man Branch, The Standard Bank of South Africa Limited, and the other financial institutions, providing for the 2025 RBL Facility.

The 2025 RBL Facility has aggregate commitments of $ 190.0 million as of March 4, 2025, with an initial borrowing base of $ 182.0 million.

The Initial Total Commitments reduce semi-annually starting from September 30, 2026.

The Borrowing base amount is calculated pursuant to the 2025 Facility Agreement and redetermined on March 31 and September 30 of each year beginning June 30, 2025 and other interim triggers set out in the 2025 Facility Agreement.

FPSO Acquisition

In February 2025, the Company, through the JOA Operator, completed the acquisition of the FPSO in Cote d'Ivoire for a total purchase price of $ 20.0 million, or approximately $ 5.5 million net cost to the Company.

Acquisition of Interest in CI-705 Block

In March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire.

The Company will become operator of the CI-705 block with a 70 % working interest and a 100 % paying interest though 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.

Acquisition costs for this transaction is approximately over $ 3.0 million.

In February 2026, the Company became the operator with a 60 % working interest in the Kossipo field on the CI-40 Block with a field development plan to be completed in the second half of 2026.

SUPPLEMENTAL INFORMATION ON CRUDE OIL, NATURAL GAS AND NGLs PRODUCING ACTIVITIES (UNAUDITED)

1 unchanged sentence

The geographic areas reported are the U.S.

(North America), which includes the producing properties in offshore Gabon and Cote d'Ivoire (Africa), and onshore in Egypt and Canada.

(North America), which includes the producing properties in offshore Gabon and Cote d'Ivoire (Africa), and onshore in Egypt as well as, prior to the Canada Asset Divestment (defined below), producing properties in Canada.

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, certain assets and liabilities associated with our Canada Asset Divestment were classified as held for sale on our Consolidated Balance Sheet.

On February 4, 2026, the Company entered into an asset purchase agreement to sell all of our operating assets in Canada.

The sale was completed on February 16, 2026 with an effective date of February 1, 2026 (the “Canada Asset Divestment”).

As of December 31, 2025, all of our proved developed and proved undeveloped reserves in Canada are attributed to assets held for sale.

Our reserves information was evaluated by the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc.

Prior to 2025, reserves information for Canada was independently evaluated by GLJ Ltd.

The proved reserve quantities are calculated based on our NRI.

Costs Incurred for Acquisition, Exploration and Development Activities

1 unchanged sentence

Gabon Egypt Canada Cote d'Ivoire Total

Year Ended December 31, 2024 (1)

(in thousands)

Year Ended December 31, 2025 (in thousands)

Exploration costs - expensed $ 3,799 $ 2,409 $ — $ 2,706 $ 8,914

Exploration costs - capitalized — 1,201 — — 1,201

Acquisition of properties — — — 3,034 3,034

1 unchanged sentence

Total $ 65,538 $ 31,177 $ 1,588 $ 148,926 $ 247,229

Gabon Egypt Canada Total

Gabon Egypt Canada Cote d'Ivoire Total

Year Ended December 31, 2024 (in thousands)

6 unchanged sentences

(in thousands)

Exploration costs - capitalized $ 47 $ — $ — $ 47

Exploration costs - expensed $ 51 $ 1,914 $ — $ 1,965

3 unchanged sentences

(1) For Cote d'Ivoire, all activity pertains to the period from April 30, 2024 to December 31, 2024 related to the Svenska Acquisition.

(2) For Egypt and Canada, all activity pertains to the period from October 14, 2022 to December 31, 2022 related to the TransGlobe Acquisition.

Capitalized Costs Relating to crude oil, natural gas and NGLs Producing Activities

10 unchanged sentences

Gabon Egypt Canada Cote d'Ivoire Total

Year Ended December 31, 2024 (2)

(In thousands)

Year Ended December 31, 2025 (In thousands)

Revenues $ 181,738 $ 139,963 $ 19,174 $ 18,397 $ 359,272

2 unchanged sentences

Depreciation, depletion, amortization (48,739) (36,649) (13,485) (10,134) (109,007)

Impairment loss on assets held for sale — — (67,224) — (67,224)

Exploration expenses (3,799) (2,409) — (2,706) (8,914)

2 unchanged sentences

Results from crude oil and natural gas producing activities $ 21,793 $ 25,553 $ (69,993) $ 5,732 $ (16,915)

Gabon Egypt Canada Total

Year Ended December 31, 2023 (In thousands)

Gabon Egypt Canada Cote d'Ivoire Total

Year Ended December 31, 2024 (2)

(In thousands)

Crude oil and natural gas sales $ 205,954 $ 145,966 $ 31,986 $ 95,082 $ 478,988

7 unchanged sentences

Gabon Egypt Canada Total

Year Ended December 31, 2022 (3)

(In thousands)

Year Ended December 31, 2023 (In thousands)

Crude oil and natural gas sales $ 260,346 $ 161,049 $ 33,671 $ 455,066

4 unchanged sentences

Other operating expense (55) (241) 729 433

Credit (recovery) losses and other (2,743) — — (2,743)

Income tax benefit (expense) (67,982) (37,271) — (105,253)

2 unchanged sentences

(2) For Cote d'Ivoire, all activity pertains to the period from April 30, 2024 to December 31, 2024 related to the Svenska Acquisition.

(3) For Egypt and Canada, all activity pertains to the period from October 14, 2022 to December 31, 2022 related to the TransGlobe Acquisition.

Estimated Quantities of Proved Reserves

43 unchanged sentences

(MMcf) Cote d'Ivoire

Balance at December 31, 2022 — — 16,539 — 16,539

Balance at January 1, 2023 — — 16,539 — 16,539

Production — — (1,528) — (1,528)

8 unchanged sentences

Balance at December 31, 2024 — — 16,080 6,551 22,631

Production — — (1,449) — (1,449)

Extensions and discoveries — — — — —

Revisions of previous estimates — — (2,422) 403 (2,019)

Balance at December 31, 2025 — — 12,209 6,954 19,163

(MMcf) Canada

4 unchanged sentences

2023 — — 9,011 — 9,011

2022 — — 11,023 — 11,023

Year-end proved undeveloped reserves:

2 unchanged sentences

2023 — — 7,921 — 7,921

2022 — — 5,516 — 5,516

Proved reserves:

3 unchanged sentences

(MBbls) Total

Balance at December 31, 2022 — — 2,797 — 2,797

Balance at January 1, 2023 — — 2,797 — 2,797

Production — — (270) — (270)

8 unchanged sentences

Balance at December 31, 2024 — — 2,680 — 2,680

Production — — (212) — (212)

Extensions and discoveries — — — — —

Revisions of previous estimates — — (687) — (687)

Balance at December 31, 2025 — — 1,781 — 1,781

(MBbls) Egypt

6 unchanged sentences

2023 — — 1,449 — 1,449

2022 — — 1,855 — 1,855

Year-end proved undeveloped reserves:

2 unchanged sentences

2023 — — 1,289 — 1,289

2022 — — 942 — 942

Total Reserves (1)

4 unchanged sentences

Production (3,197) (2,771) (859) — (6,827)

Extensions and discoveries — — — — —

Purchase of reserves — — — — —

Extensions and discoveries — 93 1,852 — 1,945

Revisions of previous estimates 2,042 4,693 (1,163) — 5,572

1 unchanged sentence

Production (2,783) (2,585) (870) (1,058) (7,296)

Extensions and discoveries — — — — —

Purchase of reserves — — — 16,465 16,465

Extensions and discoveries — — 539 — 539

Revisions of previous estimates 4,782 1,441 (534) 974 6,663

20 unchanged sentences

(1) To convert Natural Gas to MBoe, MMcf is divided by 6 for Canada reserves, and MMcf is divided by 5.8 for Cote d'Ivoire reserves.

Year Ended December 31, 2025

During 2025, the Company had net positive revisions of prior estimates of 2.8 MMBoe.

These upward revisions include an increase of 1.9 MMBoe from our Egypt segment resulting from a combination of continued development activity including active in-field drilling, workovers as well as improved, forecasted well performance.

In addition, we had an increase of 1.9 MMBoe from our Cote d’Ivoire segment which reflects improved recovery based on technical analysis of the upcoming Phase 5 drilling campaign.

The Gabon segment also contributed to an increase of 0.3 MMBoe based on improved production performance.

The upward revisions were offset by negative revisions of 1.3 MMBoe in Canada due to wells that were not reasonably expected to be developed within the five-year timeframe in accordance with the SEC guidance.

Extensions and discoveries

During 2025, the Company added 1.2 MMBoe of proved reserves through extensions, discoveries, and other additions related to the Phase 3 drilling campaign in Gabon.

Year Ended December 31, 2024

Purchases of reserves in place

For the balance at December 31, 2024, purchases of reserves in place included 16.5 MMBoe of proved reserves in Cote d'Ivoire, associated with our acquisition of Svenska Petroleum Exploration Aktiebolag (“Svenska”), and as a result, Svenska’s primary asset:

a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40.

Extensions and discoveries

For the balance at December 31, 2024, extensions and discoveries included 0.5 MMBoe of proved reserves in Canada, primarily related to the drilling of new wells.

In 2024, operations in Gabon had 4.8 MMBoe of reserves added through positive revisions of previous estimates mainly due to performance and development activities.

For Egypt, we had 1.4 MMBoe of reserves added through positive

revisions of previous estimates primarily as a result of our workover programs.

In 2024, we also added 16.5 MMBoe of reserves from our Svenska Acquisition.

For Egypt, we had 1.4 MMBoe of reserves added through positive revisions of previous estimates primarily as a result of our workover programs.

For Canada, we had 0.5 MMBoe of negative revisions of previous estimates primarily due to performance adjustments of existing wells.

For the balance at December 31, 2024, operations in Cote d'Ivoire included 1.0 MMBoe in positive revisions of reserves due to improved field performance.

Year Ended December 31, 2023

In 2023, operations in Gabon had 2.0 MMBoe of reserves added through positive revisions of previous estimates.

2.8 MMBoes of the positive revisions were due to performance offset by 0.8 MMBoe of negative revisions through price.

2.8 MMBoe of the positive revisions were due to performance offset by 0.8 MMBoe of negative revisions through price.

For Egypt at December 31, 2023, 4.7 MMBoe of reserves were added through positive revisions of previous estimates.

5.3 MMBoe of the positive revisions were due to performance offset by 0.6 MMBoe of negative revisions through price.

In 2022, operations in Gabon had 2.0 MMBoe of positive revision of reserves due to the 2021/2022 drilling campaign.

0.7 MMBoe of the positive revision was due to performance and the remaining 1.3 MMBoe of positive revisions was due to price.

For the balance at December 31, 2023, operations in Canada included 1.2 MMBoe in negative revisions of reserves due to performance adjustments of existing wells.

Extensions and discoveries

For the balance at December 31, 2023, extensions and discoveries included 0.1 MMBoe of proved reserves in Egypt, primarily related to operational improvements and the drilling of new wells and 1.9 MMBoe of proved reserves in Canada, primarily related to the drilling of new wells.

In accordance with the guidelines of the SEC, the Company does not book proved reserves on discoveries until such time as a development plan has been prepared for the discovery indicating that the development well will be drilled within five years from the date of its initial booking.

37 unchanged sentences

(1) Includes costs expected to be incurred to abandon the properties, where applicable.

International income taxes represent amounts payable to the Government of Gabon on Profit Oil as final payment of corporate income taxes, and domestic income taxes (including other expenses treated as taxes).

International income taxes represent amounts payable to the Governments of Gabon and Cote d’Ivoire on Profit Oil as final payment of corporate income taxes, and domestic income taxes (including other expenses treated as taxes).

Changes in Standardized Measure of Discounted Future Net Cash Flows

24 unchanged sentences

Such prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.

For 2024 and 2023, the average of such prices for crude oil used for our reserve estimate were as follows:

For 2025 and 2024, the average of such prices used for our reserve estimate were as follows:

Year Ended December 31,

4 unchanged sentences

Canada $ 61.61 $ 69.12

For 2024 and 2023, the adjusted average prices for our reserves associated with natural gas and NGLs were as follows:

Year Ended December 31,

Cote d'Ivoire

Natural Gas ($/Mcf)

Natural Gas ($/Mcf) $ 0.95 $ 1.91

Ethane ($/Bbl) $ 3.52 $ 5.20

Propane ($/Bbl) $ 19.46 $ 20.18

Butane ($/Bbl) $ 30.68 $ 36.69

Condensates ($/Bbl) $ 69.59 $ 74.76

Cote d'Ivoire $ 2.77 $ 2.77

Canada $ 1.07 $ 0.95

Natural Gas Liquids ($/Bbl)

Ethane $ 2.90 $ 3.52

Propane $ 19.67 $ 19.46

Butane $ 25.88 $ 30.68

Condensates $ 62.44 $ 69.59

Production Sharing Contracts

4 unchanged sentences

Instead, the Company was authorized to sell the Gabonese government’s share of production and remit the proceeds to the Gabonese government.

Beginning in February 2018, the Gabonese government elected to take physical delivery of its allocated production volumes for Profit Oil (see discussion in Note 7 above).

Beginning in February 2018, the Gabonese government elected to take physical delivery of its allocated production volumes for Profit Oil.

Please see further discussion in Note 6.

The Etame Consortium maintains a Cost Account, which entitles it to receive a portion of the production remaining after deducting the 13% royalty so long as there are amounts remaining in the Cost Account (“Cost Recovery”).

15 unchanged sentences

In addition, Equatorial Guinea imposes a 25% income tax on net profits.

The Block P PSC provides for a discovery to be reclassified into a development area with a term of 25 years.

The Block P PSC provides for a discovery to be reclassified into a development area with a

term of 25 years.

At December 31, 2025, the Company has no SEC proved reserves related to Block P in Equatorial Guinea.

2 unchanged sentences

The PSCs provide for cost recovery per quarter up to a maximum percentage of total production.

Timing differences often exist between the Company's recognition of costs and their recovery as the

Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis.

Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis.

If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as “excess”.

21 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures