VAALCO ENERGY INC /DE/ 10-K

Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer (“CEO”) and principal financial officer (“CFO”), to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures. 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. Management’s Annual Report on Internal Control Over Financial Reporting Our management, including our CEO and CFO, is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed under the supervision of our CEO and our CFO, overseen by our Board of Directors and Audit Committee, and effected by management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes using the framework in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO framework”). Such internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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, 2024 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; and • 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. 70 Table of Contents • 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. 71 Table of Contents 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. GAAP. 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. Item 9B . 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). Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections Not applicable. PART III Item 10. Directors, Executive Officers and Corporate Governance Information required by this item will be included in our proxy statement for our 2025 annual meeting, which will be filed with the SEC within 120 days of December 31, 2024, and that is incorporated herein by reference. Item 11. Executive Compensation Information required by this item will be included in our proxy statement for our 2025 annual meeting, which will be filed with the SEC within 120 days of December 31, 2024, and that is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Information required by this item under Item 403 of Regulation S-K concerning the security ownership of certain beneficial owners and management will be included in our proxy statement for our 2025 annual meeting, which will be filed with the SEC within 120 days of December 31, 2024, and which is incorporated herein by reference. 72 Table of Contents The following table provides information as of December 31, 2024 regarding the number of shares of common stock that may be issued under our compensation plans. Please refer to Part IV, Item 15., Note 17. Stock-based Compensation and Other Benefit Plans to the Consolidated Financial Statements for additional information on stock-based compensation. Plan Category Number of securities to be issued upon exercise of outstanding options, warrants, and rights Weighted average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issues under equity compensation plans (excluding securities reflected in the first column) Equity compensation plans approved by security holders 1,118,048 $ 5.32 4,022,832 Total 1,118,048 $ 5.32 4,022,832 Item 13. Certain Relationships and Related Transactions, and Director Independence Information required by this item will be included in our proxy statement for our 2025 annual meeting, which will be filed with the SEC within 120 days of December 31, 2024, and that is incorporated herein by reference. Item 14. Principal Accountant Fees and Services Information required by this item will be included in our proxy statement for our 2025 annual meeting, which will be filed with the SEC within 120 days of December 31, 2024, and that is incorporated herein by reference. 73 Table of Contents PART IV Item 15. Exhibits and Financial Statement Schedules (a) 1. The following is an index to the Financial Statements that are filed as part of this Form 10-K. VAALCO ENERGY, INC. AND SUBSIDIARIES Report of Independent Registered Public Accounting Firm ( KPMG LLP ; Houston, Texas ; PCAOB ID No. 185 ) . F - 1 Report of Independent Registered Public Accounting Firm (BDO USA, LLP; Houston, Texas; PCAOB ID No. 243) F - 4 Report of Independent Registered Public Accounting Firm Over Internal Controls over Financial Reporting (KPMG LLP; Houston, Texas; PCAOB ID No. 185) F - 5 Consolidated Balance Sheets as of December 31, 2023 and 2022 F - 7 Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2023, 2022 and 2021 F - 8 Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021 F - 9 Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 F - 10 Notes to the Consolidated Financial Statements F - 12 Supplemental Information on Crude Oil, Natural Gas and NGLs Producing Activities (Unaudited) F - 47 (a) 2. Other schedules are omitted because they are not required, not applicable or the required information is included in the Financial Statements or notes thereto. (a) 3. Exhibits: 2.1 Sale and Purchase Agreement, dated as of November 17, 2020, by and between Sasol Gabon S.A. and VAALCO Gabon S.A. (filed as Exhibit 2.1 to the Company's Annual Report on Form 10-K filed on March 9, 2021, and incorporated herein by reference). 2.2 ** Arrangement Agreement, dated as of July 13, 2022, by and among VAALCO Energy, Inc., VAALCO Energy Canada ULC and TransGlobe Energy Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on July 14, 2022 and incorporated herein by reference). 2.3 ** Share Purchase Agreement, dated February 29, 2024, by and between VAALCO Energy (Holdings), Inc., Petroswede AB (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on February 29, 2024 and incorporated herein by reference). 3.1 Restated Certificate of Incorporation as amended through May 7, 2014 (filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014, and incorporated herein by reference). 3.1.1 Certificate of Amendment to Restated Certificate of Incorporation of VAALCO, dated October 14, 2022 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 13, 2022 and incorporated herein by reference). 3.2 Third Amended and Restated Bylaws, dated July 30, 2020 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 4, 2020, and incorporated herein by reference). 3.3 Certificate of Elimination of Series A Junior Participating Preferred Stock of VAALCO Energy, Inc., dated as of December 22, 2015 (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on December 23, 2015, and incorporated herein by reference). 4.1 (a) Description of Securities 10.1 Exploration and Production Sharing Contract, dated July 7, 1995, between the Republic of Gabon and VAALCO Gabon (Etame), Inc. (filed as Exhibit 10.1 to the Company’s Annual Report on Form 10-K filed on March 7, 2018, and incorporated herein by reference). 10.2 Addendum No. 1 to Exploration and Production Sharing Contract, dated July 7, 2001, between the Republic of Gabon and VAALCO Gabon (Etame), Inc. (filed as Exhibit 10.2 to the Company’s Annual Report on Form 10-K filed on March 16, 2015, and incorporated herein by reference). 74 Table of Contents 10.3 Addendum No. 2 to Exploration and Production Sharing Contract, dated July 7, 2006, between the Republic of Gabon and VAALCO Gabon (Etame), Inc. (filed as Exhibit 10.3 to the Company’s Annual Report on Form 10-K filed on March 16, 2015, and incorporated herein by reference). 10.4 Addendum No. 3 to Exploration and Production Sharing Contract, dated November 26, 2009, between the Republic of Gabon and VAALCO Gabon (Etame), Inc. (filed as Exhibit 10.4 to the Company’s Annual Report on Form 10-K filed on March 16, 2015, and incorporated herein by reference). 10.5 Addendum No. 4 to Exploration and Production Sharing Contract, dated January 5, 2012, between the Republic of Gabon and VAALCO Gabon (Etame), Inc. (filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K filed on March 16, 2015, and incorporated herein by reference). 10.6 Addendum No. 5 to Exploration and Production Sharing Contract, dated April 25, 2016, between the Republic of Gabon and VAALCO Gabon (Etame), Inc. (filed as Exhibit 10.6 to the Company’s Annual Report on Form 10-K filed on March 7, 2018, and incorporated herein by reference). 10.7 Addendum No. 6 to Exploration and Production Sharing Contract, dated September 17, 2018, between the Republic of Gabon, VAALCO Gabon S.A., Addax Petroleum Oil & Gas Gabon, Sasol Gabon S.A. and Petroenergy Resources Corporation (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on November 7, 2018, and incorporated herein by reference). 10.8 Deed of Novation of Trustee and Paying Agent Agreement, dated June 22, 2017, between VAALCO Gabon (Etame), Inc., VAALCO Gabon S.A. and The Bank of New York Mellon, London Branch as the Trustee and Paying Agent and the Account Bank (filed as Exhibit 10.7 to the Company’s Annual Report on Form 10-K filed on March 7, 2018, and incorporated herein by reference). 10.9* VAALCO Energy, Inc. 2014 Long Term Incentive Plan (filed as Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed on April 17, 2014, and incorporated herein by reference). 10.10* Form of Restricted Stock Award Agreement under the VAALCO Energy, Inc. 2014 Long Term Incentive Plan (filed as Exhibit 10.20 to the Company’s Annual Report on Form 10-K filed on March 16, 2015, and incorporated herein by reference). 10.11* Form of Non statutory Stock Option Agreement under the VAALCO Energy, Inc. 2014 Long Term Incentive Plan (filed as Exhibit 10.21 to the Company’s Annual Report on Form 10-K filed on March 16, 2015, and incorporated herein by reference). 10.12* Form of Stock Award Agreement (for Directors) under the VAALCO Energy, Inc. 2014 Long Term Incentive Plan (filed as Exhibit 10.22 to the Company’s Annual Report on Form 10-K filed on March 16, 2015, and incorporated herein by reference). 10.13* VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 15, 2016, and incorporated herein by reference). 10.14 * Form of Stock Appreciation Rights Agreement under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 15, 2016, and incorporated herein by reference). 10.15* Form of Change in Control Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 8, 2019, and incorporated herein by reference). 10.16* VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed on April 29, 2020, and incorporated herein by reference). 10.17* First Amendment to VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 8, 2021, and incorporated herein by reference). 10.18 * Amendment No. 2 to the VAALCO Energy, Inc. 2020 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 6, 2024, and incorporated herein by reference). 10.19 * Form of Restricted Stock Award Agreement (Director) under the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 30, 2020, and incorporated herein by reference). 10.20 * Form of Restricted Stock Award Agreement (Employee) under the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on June 30, 2020, and incorporated herein by reference). 10.21 * Form of Nonqualified Stock Option Agreement under the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on June 30, 2020, and incorporated herein by reference). 10.22 * Employment Agreement, by and between VAALCO Energy, Inc. and George Maxwell, effective as of April 19, 2021 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 12, 2021, and incorporated herein by reference). 10.22.1 * Amendment No. 1 to Employment Agreement, by and between VAALCO Energy, Inc. and George Maxwell, effective as of January 27, 2022 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 28, 2022, and incorporated herein by reference). 75 Table of Contents 10.22.2 * Amendment No. 2 to Employment Agreement, by and between VAALCO Energy, Inc. and George Maxwell, effective as of November 23, 2022 (filed as Exhibit 10.21.2 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.22.3 * Amendment No. 3 to Executive Employment, effective June 6, 2024, by and between VAALCO Energy, Inc. and George W. M. Maxwell (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on August 9, 2024, and incorporated herein by reference) . 10.23* Employment Agreement, by and between VAALCO Energy, Inc. and Ronald Bain, effective as of June 21, 2021 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 22, 2021, and incorporated herein by reference). 10.23.1* Amendment No. 1 to Employment Agreement, effective as of January 27, 2022, by and between VAALCO Energy, Inc. and Ronald Bain (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 28, 2022, and incorporated herein by reference). 10.23.2* Amendment No. 2 to Employment Agreement, effective as of November 23, 2022, by and between VAALCO Energy, Inc. and Ronald Bain (filed as Exhibit 10.23.2 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.23.3* Amendment No. 3 to Executive Employment, effective June 6, 2024, by and between VAALCO Energy, Inc. and Ronald Y. Bain (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on August 9, 2024, and incorporated herein by reference). 10.24* TransGlobe Energy Corporation Amended and Restated Deferred Share Unit Plan (filed as Exhibit 10.24 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.25** Bareboat Charter, by and between VAALCO Energy, Inc. and World Carrier Offshore Services Corp, dated August 31, 2021 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on November 3, 2021, and incorporated by reference herein). 10.25.1** Deed of Novation and Amendment to Bareboat Charter, by and between VAALCO Gabon SA, World Carrier Offshore Services Corp. and Ocean Cloud Navigation Inc., dated as of November 15, 2022 (filed as Exhibit 10.25.1 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.25.2** Second Amendment to Bareboat Charter, by and between VAALCO Gabon SA and Ocean Cloud Navigation Inc., dated as of March 22, 2023 (filed as Exhibit 10.25.2 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.26** Operating Agreement, by and between VAALCO Energy, Inc. and World Carrier Offshore Services Corp, dated August 31, 2021 (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on November 3, 2021, and incorporated herein by reference). 10.26.1** Deed of Novation and Amendment to Operating Agreement, by and between VAALCO Gabon SA, World Carrier Offshore Services Corp. and Atlantic Energy Logistics SASU, dated as of November 15, 2022 (filed as Exhibit 10.26.1 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.27 Deed of Guarantee and Indemnity, by and between VAALCO Energy, Inc. and World Carrier Offshore Services Corp., dated August 31, 2021 (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on November 3, 2021, and incorporated herein by reference). 10.27.1 Deed of Novation and Amendment to Deed of Guarantee and Indemnity, by and between VAALCO Energy, Inc., World Carrier Offshore Services Corp. and Ocean Cloud Navigation Inc., dated as of November 15, 2022.(filed as Exhibit 10.27.1 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.28 Deed of Guarantee and Indemnity, by and between VAALCO Energy, Inc. and World Carrier Offshore Services Corp., dated August 31, 2021 (filed as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed on November 3, 2021, and incorporated herein by reference) 10.28.1** Deed of Novation and Amendment to Deed of Guarantee and Indemnity, by and between VAALCO Energy, Inc., World Carrier Offshore Services Corp. and Atlantic Energy Logistics SASU, dated as of November 15, 2022 (filed as Exhibit 10.28.1 to the Company’s Annual Report on Form 10-K filed on April 6, 2023, and incorporated herein by reference). 10.29 Concession Agreement for Petroleum Exploration, Development and Exploitation between The Arab Republic of Egypt and the Egyptian General Petroleum Corporation and TransGlobe West Bakr Inc. and TransGlobe West Gharib Inc. and TG NW Gharib Inc. in Merged Development Areas of West Bakr Area, West Gharib Area, Northwest Gharib Onshore Area, Eastern Desert, A.R.E. (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) 76 Table of Contents 10.30 ** 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). 10.31 ** Crude Oil Sale and Marketing Agreement, by and between VAAALCO 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). 10.32 * Amended and Restated Executive Employment, effective April 18, 2024, by and between VAALCO Energy, Inc. and Thor Pruckl (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on May 8, 2024, and incorporated herein by reference) . 10.32.1 * Amendment No. 1 to Executive Employment, effective June 6, 2024, by and between VAALCO Energy, Inc. and Thor Pruckl (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on August 9, 2024, and incorporated herein by reference). 10.33 * Executive Employment Agreement, effective January 18, 2024, by and between VAALCO Energy, Inc. and Matthew Powers (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on May 8, 2024, and incorporated herein by reference) . 10.33.1 * Amendment No. 1 to Executive Employment, effective June 6, 2024, by and between VAALCO Energy, Inc. 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). 10.34(a) ** 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. 19.1 (a) Insider Trading Policy . 21.1 (a) List of subsidiaries of the Company . 23.1 (a) Consent of BDO USA, P.C. 23.2 (a) Consent of KPMG LLP 23.3 (a) Consent of Netherland, Sewell & Associates, Inc. — Independent Petroleum Engineers. 23.4 (a) Consent of GLJ Ltd. — Independent Petroleum Engineers. 31.1 (a) Sarbanes-Oxley Section 302 certification of Principal Executive Officer. 31.2 (a) Sarbanes-Oxley Section 302 certification of Principal Financial Officer. 32.1 (b) Sarbanes-Oxley Section 906 certification of Principal Executive Officer. 32.2 (b) Sarbanes-Oxley Section 906 certification of Principal Financial Officer. 97.1 (a) Clawback Policy . 99.1 (a) Report of Netherland, Sewell & Associates, Inc. (International Properties)- Egypt 99.2 (a) Report of Netherland, Sewell & Associates, Inc. (International Properties) - Gabon 99.3 (a) Report of Netherland, Sewell & Associates, Inc. (International Properties) - Cote d'Ivoire 99.4 (a) Report of GLJ Ltd. 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. 101.SCH(a) Inline XBRL Taxonomy Schema Document. 101.CAL(a) Inline XBRL Calculation Linkbase Document. 101.DEF(a) Inline XBRL Definition Linkbase Document. 101.LAB(a) Inline XBRL Label Linkbase Document. 101.PRE(a) Inline XBRL Presentation Linkbase Document. 104(a) Cover Page Interactive Data File (formatted as Inline XBRL and Contained in Exhibit 101). _________________________________________ (a) Filed herewith (b) Furnished herewith * Management contract or compensatory plan or arrangement ** Information in this exhibit has been omitted pursuant to Item 601 of Regulation S-K. 77 Table of Contents Item 16. Form 10-K Summary None. 78 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. VAALCO ENERGY, INC. (Registrant) By /s/ George W.M. Maxwell George W.M. Maxwell Chief Executive Officer Dated March 17, 2025 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the 17th day of March 2025, by the following persons on behalf of the registrant and in the capacities indicated. Signature Title By: /s/ George Maxwell Chief Executive Officer (Principal Executive Officer) and Director George Maxwell By: /s/ Ron Bain Chief Financial Officer (Principal Financial Officer) Ron Bain By: /s/ Lynn Willis Chief Accounting Officer (Principal Accounting Officer) Lynn Willis By: /s/ Andrew L. Fawthrop Chairman of the Board and Director Andrew L. Fawthrop By: /s/ Catherine L. Stubbs Director Catherine L. Stubbs By: /s/ Fabrice Nze-Bekale Director Fabrice Nze-Bekale By: /s/ Edward LaFehr Director Edward LaFehr 79 Table of Contents Report of Independent Registered Public Accounting Firm To the Shareholders and Board of Directors VAALCO Energy, Inc.: Opinion on the Consolidated Financial Statements 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. 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. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the 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 audits 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 audits 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 audits 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 audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. 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. F-1 Table of Contents 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. For the year ended December 31, 2024, the Company recorded depreciation, depletion and amortization expense of $143 million. The estimation of proved reserves requires the expertise of reserve engineer specialists, who take into consideration future production, future operating and capital costs, and historical crude oil, natural gas and NGLs prices inclusive of price differentials. 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. 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. Specifically, auditor judgment was required to evaluate the assumptions used by the Company related to future production and future operating and capital costs. 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 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 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 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. F-2 Table of Contents 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 relevant price differentials used by the Company by comparing them to historical results. 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. 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. /s/ KPMG LLP We have served as the Company’s auditor since 2023. Houston, Texas March 17, 2025 F-3 Table of Contents 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 F-4 Table of Contents Report of Independent Registered Public Accounting Firm To the Shareholders and Board of Directors VAALCO Energy, Inc.: Opinion on Internal Control Over Financial Reporting We have audited VAALCO Energy, Inc. and subsidiaries' (the Company) 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. 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. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. F-5 Table of Contents Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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. /s/ KPMG LLP Houston, Texas March 17, 2025 F-6 VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 2024 2023 (in thousands) ASSETS Current assets: Cash and cash equivalents $ 82,650 $ 121,001 Restricted cash 143 114 Receivables: Trade, net of allowances for credit loss and other of $ 0.2 million and $ 0.5 million, respectively 94,778 44,888 Accounts with joint venture owners, net of allowance for credit losses of $ 1.5 million and $ 0.8 million, respectively 179 1,814 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 Crude oil inventory 9,441 1,948 Prepayments and other 14,973 12,434 Total current assets 237,927 228,141 Crude oil, natural gas and NGLs properties and equipment, net 538,103 459,786 Other noncurrent assets: Restricted cash 8,665 1,795 Value added tax and other receivables, net of allowances for credit loss and other of $ 0.8 million and $ 0.0 million, respectively 10,094 4,214 Right of use operating lease assets 17,254 2,378 Right of use finance lease assets 79,849 89,962 Deferred tax assets 55,581 29,242 Abandonment funding 6,268 6,268 Other long-term assets 1,209 1,430 Total assets $ 954,950 $ 823,216 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable $ 11,756 $ 22,152 Accounts with joint venture owners 3,324 5,990 Accrued liabilities and other 107,710 67,597 Operating lease liabilities - current portion 3,512 2,396 Finance lease liabilities - current portion 13,383 10,079 Foreign income taxes payable 42,043 19,261 Total current liabilities 181,728 127,475 Asset retirement obligations 78,592 47,343 Operating lease liabilities - net of current portion 13,903 33 Finance lease liabilities - net of current portion 67,377 78,293 Deferred tax liabilities 93,904 73,581 Other long-term liabilities 17,863 17,709 Total liabilities 453,367 344,434 Commitments and contingencies (Note 12) Shareholders’ equity: Preferred stock, $ 25 par value; 500,000 shares authorized, none issued — — Common stock, $ 0.10 par value; 160,000,000 shares authorized, 122,304,124 and 121,397,553 shares issued, 103,743,163 and 104,346,233 shares outstanding, respectively 12,230 12,140 Additional paid-in capital 362,578 357,498 Accumulated other comprehensive income (loss) ( 4,962 ) 2,880 Less treasury stock, 18,560,931 and 17,051,320 shares, respectively, at cost ( 78,024 ) ( 71,222 ) Retained earnings 209,761 177,486 Total shareholders' equity 501,583 478,782 Total liabilities and shareholders' equity $ 954,950 $ 823,216 See notes to consolidated financial statements. F-7 VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2024 2023 2022 (in thousands, except per share amounts) Revenues: Crude oil, natural gas and natural gas liquids sales $ 478,988 $ 455,066 $ 354,326 Operating costs and expenses: Production expense 163,500 153,157 112,661 FPSO demobilization and other costs — 7,484 8,867 Exploration expense 48 1,965 258 Depreciation, depletion and amortization 143,034 115,302 48,143 General and administrative expense 29,684 23,840 10,077 Credit (recovery) losses and other 6,304 ( 4,906 ) 3,082 Total operating costs and expenses 342,570 296,842 183,088 Other operating expense, net 78 433 38 Operating income 136,496 158,657 171,276 Other income (expense): Derivative instruments gain (loss), net ( 745 ) 232 ( 37,812 ) Interest expense, net ( 3,732 ) ( 6,452 ) ( 2,034 ) Bargain purchase gain 13,532 ( 1,412 ) 10,819 Other income (expense), net ( 5,754 ) ( 894 ) ( 18,939 ) Total other income (expense), net 3,301 ( 8,526 ) ( 47,966 ) Income before income taxes 139,797 150,131 123,310 Income tax expense 81,307 89,777 71,420 Net income $ 58,490 $ 60,354 $ 51,890 Other comprehensive income (loss) Currency translation adjustments ( 7,842 ) 1,701 1,179 Comprehensive income $ 50,648 $ 62,055 $ 53,069 Basic net income per share: Net income per share $ 0.56 $ 0.56 $ 0.74 Basic weighted average shares outstanding 103,669 106,376 69,568 Diluted net income per share: Net income per share $ 0.56 $ 0.56 $ 0.73 Diluted weighted average shares outstanding 103,747 106,555 69,982 See notes to consolidated financial statements F-8 VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS ’ EQUITY Common Shares Issued Treasury Shares Common Stock Additional Paid-In Capital Accumulated Other Comprehensive Loss Treasury Stock Retained Earnings Total (in thousands) Balance at January 1, 2022 69,562 ( 10,939 ) 6,956 76,700 — ( 43,847 ) 104,488 $ 144,297 Shares issued - stock-based compensation 614 — 61 251 — — — 312 Stock-based compensation expense — — — 2,105 — — — 2,105 Conversion of Liability Awards to Equity — — — 5,336 — — — 5,336 Acquisition of TransGlobe 49,307 — 4,931 269,214 — — — 274,145 Treasury stock — ( 691 ) — — — ( 3,805 ) — ( 3,805 ) Dividend distributions — — — — — — ( 9,354 ) ( 9,354 ) Other comprehensive income — — — — 1,179 — — 1,179 Net income — — — — — — 51,890 51,890 Balance at December 31, 2022 119,483 ( 11,630 ) $ 11,948 $ 353,606 $ 1,179 $ ( 47,652 ) $ 147,024 $ 466,105 Shares issued - stock-based compensation 1,915 — 192 482 — — — 674 Stock-based compensation expense — — — 3,410 — — — 3,410 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 Net income — — — — — — 60,354 60,354 Balance at December 31, 2023 121,398 ( 17,051 ) $ 12,140 $ 357,498 $ 2,880 $ ( 71,222 ) $ 177,486 $ 478,782 Shares issued - stock-based compensation 906 — 90 357 — — — 447 Stock-based compensation expense — — — 4,723 — — — 4,723 Treasury stock — ( 1,510 ) — — — ( 6,802 ) — ( 6,802 ) Dividend distributions — — — — — — ( 26,215 ) ( 26,215 ) Other comprehensive loss — — — — ( 7,842 ) — — ( 7,842 ) Net income — — — — — — 58,490 58,490 Balance at December 31, 2024 122,304 ( 18,561 ) $ 12,230 $ 362,578 $ ( 4,962 ) $ ( 78,024 ) $ 209,761 $ 501,583 See notes to consolidated financial statements. F-9 VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2024 2023 2022 (in thousands) 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: Depreciation, depletion and amortization 143,034 115,302 48,143 Bargain purchase gain ( 13,532 ) 1,412 ( 10,819 ) Exploration expense 48 1,841 — Deferred taxes ( 16,785 ) ( 2,864 ) 44,805 Unrealized foreign exchange loss 8 52 ( 1,043 ) Stock-based compensation 4,435 3,323 2,200 Cash settlements paid on exercised stock appreciation rights ( 154 ) ( 378 ) ( 827 ) Derivative instruments (gain) loss, net 745 ( 232 ) 37,812 Cash settlements paid on matured derivative contracts, net ( 453 ) ( 127 ) ( 42,935 ) Cash settlements paid on asset retirement obligations ( 368 ) ( 6,747 ) ( 6,577 ) Credit losses and other 6,304 7,543 3,082 Other operating loss, net 34 55 ( 38 ) Equipment and other expensed in operations 2,505 3,196 2,052 Change in operating assets and liabilities: Trade receivables, net ( 49,890 ) 6,723 18,385 Accounts with joint venture owners, net ( 757 ) 19,571 ( 18,929 ) Egypt receivables and other, net 5,644 14,802 ( 9,290 ) Crude oil inventory 7,488 1,387 ( 1,742 ) Prepayments and other ( 4,817 ) 4,743 ( 4,387 ) Value added tax and other receivables ( 7,110 ) 2,427 ( 5,193 ) Other long-term assets 2,869 3,830 ( 2,730 ) Accounts payable ( 13,198 ) ( 28,102 ) 23,920 Foreign income taxes receivable (payable) 22,682 22,030 ( 5,897 ) Accrued liabilities and other ( 33,504 ) ( 6,544 ) 6,964 Net cash provided by operating activities 113,718 223,597 128,846 CASH FLOWS FROM INVESTING ACTIVITIES: Property and equipment expenditures ( 102,996 ) ( 97,223 ) ( 159,897 ) Acquisition of crude oil and natural gas properties 877 — 36,686 Net cash used in investing activities ( 102,119 ) ( 97,223 ) ( 123,211 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from the issuances of common stock 447 673 312 Dividend distribution ( 26,216 ) ( 26,772 ) ( 9,354 ) Treasury shares ( 6,802 ) ( 23,570 ) ( 3,805 ) Deferred financing costs — — ( 2,069 ) Payments of finance lease ( 10,477 ) ( 7,150 ) ( 3,039 ) Net cash used in in financing activities ( 43,048 ) ( 56,819 ) ( 17,955 ) Effects of exchange rate changes on cash ( 3 ) ( 153 ) ( 218 ) NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH ( 31,452 ) 69,402 ( 12,538 ) CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD 129,178 59,776 72,314 CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD $ 97,726 $ 129,178 $ 59,776 See notes to consolidated financial statements. F-10 VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES Year Ended December 31, 2024 2023 2022 (in thousands) Supplemental disclosure of cash flow information: Income taxes paid in-kind with crude oil $ 37,469 $ 32,776 $ 26,257 Interest paid, net of amounts capitalized $ 6,714 $ 9,122 $ 1,656 Supplemental disclosure of non-cash investing and financing activities: Property and equipment additions incurred but not paid at end of period $ 9,479 $ 14,137 $ 41,060 Non-cash consideration exchanged in the acquisition of TransGlobe $ — $ — $ 274,145 Recognition of right-of-use operating lease assets and liabilities $ 17,649 $ 2,582 $ — Recognition of right-of-use finance lease assets and liabilities $ — $ 7,875 $ 87,166 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 $ 27,424 $ 2,487 $ — See notes to consolidated financial statements. F-11 VAALCO ENERGY, INC. AND SUBSIDIARIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs properties. We have a diversified African-focused asset portfolio in Gabon, Egypt, Cote d'Ivoire, Nigeria and Equatorial Guinea, as well as producing properties in Canada. 2 . 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. Investments in unincorporated joint ventures and undivided interests in certain operating and non-operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation. Use of estimates – The preparation of the Financial Statements in conformity with generally accepted accounting principles in the U.S. (“GAAP”) requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates. Estimates of crude oil, natural gas and NGLs reserves used to estimate depletion expense and impairment charges, as well as to estimate the fair value of assets and liabilities acquired in business combinations, require significant judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information becomes available. Cash and cash equivalents – Cash and cash equivalents includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks associated with cash and cash equivalents. Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and estimated timing of usage. 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. 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 . F-12 The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the amounts shown in the consolidated statements of cash flows. As of December 31, 2024 2023 (in thousands) Cash and cash equivalents $ 82,650 $ 121,001 Restricted cash - current 143 114 Restricted cash - non-current 8,665 1,795 Abandonment funding 6,268 6,268 Total cash, cash equivalents and restricted cash $ 97,726 $ 129,178 Trade, net – The Company’s trade accounts receivable results from sales of crude oil, natural gas and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses and other below. Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements. For credit loss and other allowances associated with accounts with joint venture owners, see allowance for credit loss and other below. Egypt receivables and other, net – 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. For credit losses associated with Egypt receivables and other, net, see allowance for credit losses and other below. Value added tax and other receivables, net – The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). As of December 31, 2024 and 2023 , the outstanding VAT receivable balance was approximately $ 6.4 million and $ 1.6 million, net to VAALCO, respectively. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other expense, net” line item of the consolidated statements of operations and comprehensive income. For the allowance associated with VAT, see allowance for credit losses and other below. Allowance for credit losses and other – On January 1, 2023 , the Company adopted Accounting Standards Update 2016 - 13, Financial Instruments—Credit Losses (“ ASU 2016 - 13 ”). ASU 2016 - 13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates. All other amounts previously disclosed as allowances for bad debt were transferred to allowances for credit loss and other. The Company estimates the current expected credit loss and other allowances based primarily using either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached F-13 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: • Trade, net; • Accounts with joint venture owners, net; • Egypt receivables and other, net; and • 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. The following table provides an analysis of the change in the aggregate credit loss and other allowances: Year Ended December 31, 2024 2023 (in thousands) Allowance for credit losses and other Balance at beginning of period $ ( 6,029 ) $ ( 8,704 ) Credit losses and other ( 6,304 ) ( 7,543 ) Credit recoveries and other ( 1,421 ) 12,449 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 $ ( 2,554 ) $ ( 6,029 ) 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 Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. Prepayments and other – Included in “Prepayments and other” line item of the Company’s December 31, 2024 and 2023 consolidated balance sheet are the following assets: 2024 2023 (in thousands) Egypt advances to contractors $ 3,665 $ 2,656 Gabon prepaid royalties 3,089 1,246 Deposits 2,933 726 Employee loans and advances 1,430 1,305 Prepaid insurance 650 474 Derivative receivables 119 403 Prepaid fixed asset progress payments 9 2,314 Other prepayments 3,078 3,310 Total prepayments and other $ 14,973 $ 12,434 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. F-14 • Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. • Capitalized equipment, spare parts and other – Capitalized equipment, spare parts and other represents the costs incurred in purchasing and bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle. • Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block basis under the unit-of-production method based upon estimates of total proved developed reserves. Depletion of leasehold acquisition costs are provided on a block basis under the unit-of-production method based upon estimates of total proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, natural gas and NGLs producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically five years for office and miscellaneous equipment and five to seven years for leasehold improvements. • Unproved Property Cost – Significant unproved properties are assessed individually for impairment and when events or circumstances indicate that the carrying value of property may not be recovered a valuation allowance is provided if an impairment is indicated. The unproved property costs are not subject to depreciation, depletion and amortization, until they are classified as proved properties. • Impairment – The Company reviews the crude oil, natural gas and NGLs properties and equipment, net for impairment on a block basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or periods of sustained declines in commodity prices. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. 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. F-15 Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842 , Leases. If a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments. Asset retirement obligations ( “ ARO ” ) – The Company has legal obligations to remove tangible equipment and restore land or seabed at the end of crude oil, natural gas and NGLs production operations. The removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of onshore or offshore crude oil, natural gas and NGLs platforms, and capping pipelines. Estimating the future restoration and removal costs requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with crude oil, natural gas and NGLs properties and equipment, net. The Company uses current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil, natural gas and NGLs properties and equipment, net. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related capitalized asset retirement cost or through a charged to earnings, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a units-of-production basis for crude oil, natural gas and NGLs properties and equipment, net production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. Revenue recognition – The Company's revenues are derived from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers. Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. 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 has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Revenues associated with the sales of the Company’s crude oil, natural gas, condensates and natural gas liquids (“NGLs”) are recognized by reference to actual volumes sold and quoted market prices in active markets for crude oil, natural gas, condensates and NGLs, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs. Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled. F-16 Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award. For restricted stock awards, the grant date fair value is determined using the market value of the common stock on the date of grant. The stock-based compensation expense for equity awards is recognized over the period that services are provided. For awards considered liabilities under US GAAP, awards are measured at fair value on the grant date and remeasured at fair value until the award is settled. Legal Contingencies – We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue losses associated with legal claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. Foreign currency transactions – The U.S. dollar is the functional currency of the Company’s foreign operating subsidiaries except for Canada which has a functional currency of the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income (loss). The Company recognized losses on foreign currency transactions of $ 1.8 million in 2024 , $ 0.9 million in 2023 and $ 4.2 million in 2022 . Income taxes – The tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil, which is due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, will not be realized. A valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered are earnings generated in previous periods, forecasted earnings and the expiration period of carryovers. Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating F-17 to the marketing of a portion of our crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations and comprehensive income (loss). Fair value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows: Level 1 – Inputs are observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Level 2 – Inputs are observable market-based inputs or unobservable inputs that are corroborated by market data. Level 3 – Inputs are unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, natural gas and NGLs properties and equipment, net, asset retirement assets and liabilities and assets acquired and liabilities assumed in a business combination. 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 cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows. The expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors, most of which are often outside of management's control. However, assumptions used to reflect a market participant's view of long term prices, costs and other factors and are consistent with assumptions used in VAALCO'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. As of December 31, 2024 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset Prepayments and other $ — $ 119 $ — $ 119 Derivative asset L-T Other long term assets — 1,209 — 1,209 $ — $ 1,328 $ — $ 1,328 Liabilities SARs liability Accrued liabilities and other $ — $ — $ — $ — Derivative liability Accrued liabilities and other — 17 — 17 $ — $ 17 $ — $ 17 F-18 As of December 31, 2023 Balance Sheet Line Level 1 Level 2 Level 3 Total (in thousands) Assets Derivative asset Prepayments and other $ — $ 403 $ — $ 403 $ — $ 403 $ — $ 403 Liabilities SARs liability Accrued liabilities and other $ — $ 163 $ — $ 163 $ — $ 163 $ — $ 163 Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. 3 . NEW ACCOUNTING STANDARDS Adopted In 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. 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): Disaggregation of Income Statement Expenses to improve financial reporting by requiring that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. VAALCO is currently evaluating the impact of adopting this ASU to our notes to the consolidated financial statements. F-19 4 . ACQUISITIONS 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. The Svenska Acquisition qualified as a business combination and was accounted for using the acquisition method of accounting. The following tables summarize the cash paid for the purchase price and the final purchase price allocation of the acquisition consideration. April 30, 2024 Measurement Period Adjustment April 30, 2024 (As Adjusted) (in thousands) Purchase Consideration Cash $ 40,166 $ — $ 40,166 Total purchase consideration $ 40,166 $ — $ 40,166 April 30, 2024 Measurement Period Adjustment April 30, 2024 (As Adjusted) (in thousands) Assets acquired: Cash and cash equivalents $ 31,789 $ 466 $ 32,255 Other receivables, net 830 — 830 Crude oil inventory 14,981 — 14,981 Prepayments and other 409 — 409 Crude oil, natural gas and NGLs properties and equipment, net 100,188 6,901 107,089 Restricted cash 8,788 — 8,788 Other LT receivables 33 — 33 Deferred tax asset 28,153 ( 12,095 ) 16,058 Total assets acquired 185,171 ( 4,728 ) 180,443 Liabilities assumed: Accounts payable ( 2,506 ) — ( 2,506 ) State oil liability ( 19,447 ) — ( 19,447 ) Accrued tax settlement ( 8,788 ) — ( 8,788 ) Accrued accounts payable invoices ( 21,692 ) — ( 21,692 ) Accrued liabilities and other ( 19,083 ) ( 301 ) ( 19,384 ) Asset retirement obligations ( 15,694 ) ( 11,617 ) ( 27,311 ) Deferred tax liability ( 37,897 ) 10,280 ( 27,617 ) Total liabilities acquired ( 125,107 ) ( 1,638 ) ( 126,745 ) Bargain purchase gain ( 19,898 ) 6,366 ( 13,532 ) Total purchase price $ 40,166 $ — $ 40,166 F-20 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. 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. 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 . The table below summarizes amounts contributed by the Cote d’Ivoire assets acquired in the Svenska Acquisition to the Company's consolidated results for the period from April 30, 2024 through December 31, 2024 . April 30, 2024 through December 31, 2024 (in thousands) Crude oil, natural gas and natural gas liquids sales $ 95,082 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 do not purport to represent what the Company’s F-21 actual results of operations would have been if the Svenska Acquisition had been completed on such date or to project the Company’s results of operations for any future date or period. Year Ended December 31, 2024 2023 (in thousands) Pro forma (unaudited) Crude oil, natural gas and natural gas liquids sales $ 510,513 $ 632,514 Operating income $ 120,681 243,228 Net income (loss) (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. F-22 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 Basic weighted average shares outstanding 108,206 108,206 108,206 Diluted net income per share: $ 1.20 $ 0.01 (d) $ 1.21 Diluted weighted average shares outstanding 108,642 108,642 108,642 (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. F-23 5 . 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 Revenues: 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 F-24 Year Ended December 31, 2023 (in thousands) Gabon Egypt Canada Equatorial Guinea Corporate and Other Total Revenues: 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. F-25 Year Ended December 31, 2022 (in thousands) Gabon Egypt Canada Equatorial Guinea Corporate and Other Total Revenues: 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 F-26 6 . EARNINGS PER SHARE Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method. A reconciliation of reported net income (loss) to net income (loss) used in calculating EPS as well as a reconciliation from basic to diluted shares follows: Year Ended December 31, 2024 2023 2022 (in thousands) Net income (numerator): Net income $ 58,490 $ 60,354 $ 51,890 Income attributable to unvested shares ( 714 ) ( 632 ) ( 593 ) Numerator for basic 57,776 59,722 51,297 Loss attributable to unvested shares — 1 3 Numerator for dilutive $ 57,776 $ 59,723 $ 51,300 Weighted average shares (denominator): Basic weighted average shares outstanding 103,669 106,376 69,568 Effect of dilutive securities 78 179 414 Diluted weighted average shares outstanding 103,747 106,555 69,982 Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive 516 385 189 7 . REVENUE Production Sharing Contracts Exploration and production activities of our assets in Gabon, Egypt, Cote d'Ivoire, and Equatorial Guinea are generally governed by PSCs. Our oil entitlement under the PSCs is generally the sum of cost oil, profit oil and excess cost oil, if applicable. Under the terms of the PSCs, the Company is typically the contractor partner (“Contractor”) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred (“Cost Oil”) and a stipulated share of production after cost recovery (“Profit Oil”). The Contractor may be obligated to make royalty payments to the host government of each country using a variable percentage based on gross daily production levels. The remaining oil production, after deducting the gross royalty, if any, is split between Cost Oil and Profit Oil. Cost Oil is up to a maximum percentage and is allocated to recover approved operating and capital costs spent on specific projects. Excess Cost Oil, which is Cost Oil less the actual cost recovery, is further shared between the host government and the Contractor. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale. Our share of royalties is paid out of the government's share of production. Additionally, the income tax to which the Contractor is subject to (“Profit Oil Tax”), is deemed to have been paid to the host government as part of the payment of Profit Oil or is captured in the entitled share of Profit Oil production paid in-kind to the host government, and therefore no additional tax burden is due. Under this arrangement taxation is based on a set percentage of average daily production volume. F-27 Gabon Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements (“COSMA or COSMAs”). Except for internal costs, which are expensed as incurred, there are no upfront costs associated with obtaining a new COSPA or COSMA. Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO or FSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically as operator, the volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the volumes sold exceeded the Company’s ownership interest. For each lifting completed under a COSPA or COSMA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The terms of the Etame PSC includes provisions for payments to the government of Gabon for: royalties based on 13 % of production at the published price and a shared portion of Profit Oil determined based on daily production rates, as well as a gross carried working interest of 7.5 % (increasing to 10 % beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments. To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment. Payments for royalties are reflected as a reduction in revenues from customers. With respect to the government’s share of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the consolidated statements of operations and comprehensive income (loss), the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. The amount associated with the Profit Oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported in current income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, which is the period in which it lifts the crude oil. 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. Certain amounts associated with the carried interest in the Etame Marin block are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs that would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues. The following table presents revenues in Gabon from contracts with customers as well as revenues associated with the obligations under the Etame PSC: F-28 Year Ended December 31, 2024 2023 2022 Revenues from customer contracts: (in thousands) Sales under the COSPA or COSMA $ 205,965 $ 261,801 $ 320,522 Other items reported in revenue not associated with customer contracts: Gabonese government share of Profit Oil taken in-kind 30,256 32,776 26,257 Carried interest recoupment 2,276 5,301 5,843 Royalties ( 32,543 ) ( 39,532 ) ( 45,847 ) Net revenues $ 205,954 $ 260,346 $ 306,775 Egypt Revenues from sales in Egypt are generally made through direct sales to EGPC or through contracts with customers pursuant to crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements (“COSMA or COSMAs”). EGPC and the Company each own a 50 % interest, respectively, in the operating company which is a party to the Merged Concession Agreement. EGPC and the Company each also own a 50 % interest, respectively, in the operating company that is a party to the South Ghazalat concession agreement. Customer sales generally occur when sales are directly to EGPC or haphazardly production is sold through a cargo lifting. The Company records EGPC’s share of production as royalties which are netted against revenue, whether EGPC’s share of production arises from EGPC’s share of Profit Oil or excess Cost Oil. With respect to Egyptian income taxes, these taxes are paid by EGPC on behalf of the Company out of EGPC’s share of production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of the Company are recognized as crude oil revenue and income tax expense 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. 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. Imbalances are valued based on the actual sales proceeds and the Company will record a payable, if in an overlift position, or a receivable, if in an underlift position, based on the fair value of the consideration received or receivable. The following table presents revenues in Egypt from contracts with customers: Year Ended December 31, 2024 2023 2022 Revenues from customer contracts: (in thousands) Gross sales $ 250,946 $ 272,613 $ 56,452 Royalties ( 104,449 ) ( 110,569 ) ( 18,742 ) Selling costs ( 531 ) ( 995 ) — Net revenues $ 145,966 $ 161,049 $ 37,710 Canada 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 F-29 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. The following table presents revenues in Canada from contracts with customers: Year Ended December 31, 2024 2023 2022 Revenues from customer contracts: (in thousands) Oil revenue $ 28,418 $ 28,287 $ 7,362 Gas revenue 1,849 3,467 1,340 NGL revenue 7,646 8,440 2,235 Other revenue 213 — 41 Royalties ( 5,009 ) ( 5,821 ) ( 1,137 ) Selling costs ( 1,131 ) ( 702 ) — Net revenues $ 31,986 $ 33,671 $ 9,841 Cote d'Ivoire 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. Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. The volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the volumes sold exceeded the Company’s ownership interest. For each lifting completed under the sales and purchase agreement, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. Cost Oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the government state oil company. Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the government of Cote d'Ivoire (the “Ivorian Government”). The Ivorian Governments’ share of Profit oil attributable to the Company’s equity interest is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. In addition, under the terms of the Cote d'Ivoire PSC, the tax payments to the Ivorian Government are deemed satisfied by its share of the Profit Oil. F-30 The following table presents revenues in Cote d'Ivoire from contracts with customers: Year Ended December 31, 2024 Revenues from customer contracts: (in thousands) Sales under the sales and purchase agreements $ 87,870 Other item reported in revenue not associated with customer contracts: Cote d’Ivoire government share of Profit Oil taken in-kind 7,212 Net revenues $ 95,082 Information about the Company ’ s most significant customers - For the years ended December 31, 2024, 2023 and 2022, our revenue concentration by customer for each operating segment are shown on the table below. Year Ended December 31, 2024 (1) 2023 2022 (2) Gabon 100 % 100 % 100 % Egypt 100 % 62 % and 38 % 100 % Cote d'Ivoire 87 % and 13 % — % — % Canada 41 %, 32 % and 21 % 52 %, 37 % and 7 % 54 %, 32 % and 14 % (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. 8 . INCOME TAXES Income (loss) before income taxes is attributable as follows: Year Ended December 31, (in thousands) 2024 2023 2022 U.S. $ ( 26,337 ) $ ( 15,781 ) $ ( 56,750 ) Foreign 166,134 165,927 180,132 $ 139,797 $ 150,146 $ 123,382 Provision for income taxes related to income (loss) consists of the following: Year Ended December 31, 2024 2023 2022 U.S. Federal: (in thousands) Current $ — $ — $ — Deferred ( 1,698 ) 6,214 ( 3,344 ) Foreign: Current 98,882 92,642 26,615 Deferred ( 15,877 ) ( 9,079 ) 48,149 Total $ 81,307 $ 89,777 $ 71,420 F-31 The reconciliation of income tax expense (benefit) to income tax at the U.S. statutory rate is as follows: Year Ended December 31, (in thousands) 2024 2023 2022 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 Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered. In assessing the realizability of the deferred tax assets, the Company considers all available positive and negative evidence by jurisdiction to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, future operating conditions, particularly as related to prevailing crude oil prices. On the basis of this evaluation, as of December 31, 2024, a valuation allowance of $ 173.1 million has been recorded to recognize only the portion of the deferred tax asset that is more likely than not to be realized. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows: December 31, (in thousands) 2024 2023 Deferred tax assets: Fixed assets(1) $ 35,541 $ 9,132 Foreign tax credit carryforward 123,660 55,069 Net operating losses 56,317 32,306 Asset retirement obligations 20,384 9,631 ROU lease liabilities 9,973 10,345 Accrued liabilities 19,686 3,808 Receivables ( 1,788 ) ( 146 ) Other 2,682 719 Total deferred tax assets 266,455 120,864 Valuation allowance ( 173,140 ) ( 83,893 ) Net deferred tax assets $ 93,315 $ 36,971 Deferred tax liabilities: Basis difference in fixed assets ( 131,639 ) ( 81,310 ) Net deferred tax liabilities $ ( 131,639 ) $ ( 81,310 ) (1) This line includes ROU lease asset. F-32 The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2024, it is not practicable to estimate the unrecognized deferred tax liability. However, unrecognized deferred taxes on remittance of these funds are not expected to be material. The Company has NOL’s, in the following jurisdictions as of December 31, 2024: Jurisdiction Amount (in thousands) Expiration Period U.S. $ — No expiration Gabon $ — No expiration Egypt $ 18,322 2025-2029 Canada $ 77,132 2032-2041 Equatorial Guinea $ 124,589 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. The Company believes that its income tax positions and deductions will be sustained on audit, and therefore no reserves for uncertain tax positions have been established. Accordingly, no interest or penalties have been accrued as of December 31, 2024 and 2023. The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2024 , 2023 and 2022, the Company is subject to foreign and U.S. federal taxes only, with no allocations made to state and local taxes. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions. Jurisdiction Years U.S. 2014 - 2024 Gabon 2020 - 2024 Egypt 2019 - 2024 Canada 2019 - 2024 Sweden 2018 - 2024 Cote d'Ivoire 2020 - 2024 9. 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: 2024 2023 (in thousands) Crude oil, natural gas and NGLs properties and equipment, net Wells, platforms and other production facilities $ 1,593,243 $ 1,468,542 Work-in-progress 44,517 4,183 Unproved properties 60,761 52,109 Capitalized equipment, spare parts and other 75,581 47,794 1,774,102 1,572,628 Accumulated depreciation, depletion, amortization and impairment ( 1,235,999 ) ( 1,112,842 ) Crude oil, natural gas and NGLs properties and equipment, net $ 538,103 $ 459,786 F-33 Unproved property costs See the table below for the list of unproved property costs at December 31, 2024 and 2023 , respectively: 2024 2023 (in thousands) Unproved Property Costs Etame Marin Block $ 13,735 $ 13,735 Equatorial Guinea 10,000 10,000 Egypt 11,542 11,444 Cote d'Ivoire 12,775 — Canada 12,709 16,930 Unproved Property Costs $ 60,761 $ 52,109 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 . 10 . 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 (Bbls) b (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 (GJ) b (per GJ) January 2025 - March 2025 Swap AECO (7A) 67,000 $ 2.80 b) One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is about 25.5 cubic metres at standard conditions. F-34 The following table sets forth the gain (loss) on derivative instruments on the Company’s consolidated statements of operations and comprehensive income (loss): Year Ended December 31, Derivative Item Statements of Operations Line 2024 2023 2022 (in thousands) Commodity derivatives Cash settlements paid on matured derivative contracts, net $ ( 453 ) $ ( 127 ) $ ( 42,935 ) Unrealized gain (loss) ( 292 ) 359 5,123 Derivative instruments gain (loss), net $ ( 745 ) $ 232 $ ( 37,812 ) 11. ASSET RETIREMENT OBLIGATIONS The following table summarizes the changes in the Company’s asset retirement obligations: Year Ended December 31, (in thousands) 2024 2023 Asset retirement obligation $ 47,343 $ 42,001 Accretion 4,753 2,352 Additions 27,424 2,487 Revisions 981 6,889 Settlements ( 368 ) ( 6,747 ) Foreign currency gain (loss) ( 367 ) 361 Total asset retirement obligation 79,766 47,343 Less: current obligations ( 1,174 ) — Long-term asset retirement obligation $ 78,592 $ 47,343 Accretion is recorded in the line item “Depreciation, depletion and amortization” on the consolidated statements of operations and comprehensive income (loss). 12 . COMMITMENTS AND CONTINGENCIES Abandonment funding Gabon Under the terms of the Etame PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the life of the Etame Marin Block, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In August 2023 , 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. At December 31, 2024, $ 10.7 million ($ 6.3 million, net to VAALCO) on an undiscounted basis has been funded. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. In the first quarter of 2023 , the Directorate of Hydrocarbons in Gabon approved a $ 26.6 million ($ 15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $ 15.6 F-35 million in March 2023 . No other activity occurred in the abandonment funding account during the remainder of 2023 and in 2024. 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. FPSO charter 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. Regulatory and Joint Interest Audits and Related Matters The Company is subject to periodic audits by various government agencies from the international jurisdictions where we operate, including audits by the respective governments and other members of the Company's joint operating agreements. Merged Concession Agreement The Company is a party to the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”). In accordance with the Merged Concession Agreement, we 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. The Company also has minimum financial work commitments of $ 50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 for a total of $ 150 million over the 15 year license contract term. Through December 31, 2024 , the Company's financial work commitments have exceeded the five-year minimum $ 50 million threshold and any excess carries forward to offset against subsequent five-year commitments. The amounts that will be paid for such outstanding off-balance sheet financial work commitments as of December 31, 2024 are $ 10.0 million in 2025 , $ 10.0 million in 2026 , $ 10.0 million in 2027 , $ 10.0 million in 2028, $ 10.0 million in 2029 and $ 60.0 million in 2030 and thereafter. Domestic Market Obligation Under the terms of the respective PSCs in Gabon and Cote d'Ivoire, the Company can be required to sell to the Government or another entity designated by the Government, a certain percentage of its Profit Oil to meet the needs of the domestic market. 13. DEBT As of December 31, 2024 and 2023, the Company had no outstanding debt. RBL Facility 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 F-36 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. See Note 20. Subsequent Events for additional discussion on the terms of the 2025 Facility Agreement. 14 . LEASES Under the leasing standard that became effective January 1, 2019 , there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments. Operating leases The Company is currently a party to two operating lease agreements for the corporate office and transportation equipment. The remaining lease term for these agreements ranges from 47 to 65 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for certain equipment used in the joint operations includes the gross amount of the lease components. The transportation equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the number of days or hours the asset is deployed. Because the Company does not F-37 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. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. All leases For all leases that contain an option to extend the initial lease term, the Company has evaluated whether it is reasonably certain that the Company will extend the lease beyond the initial lease term. When the Company believes it is reasonably certain it will utilize these leased assets beyond the initial lease term, those payments have been included in the calculation of the ROU assets and liabilities. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. The Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments. For the years ended December 31, 2024, 2023 and 2022, the components of the lease costs and supplemental information was as follows: Year Ended December 31, 2024 2023 2022 Lease cost: (in thousands) Finance lease cost (1) $ 19,198 $ 17,297 $ 3,682 Operating lease cost 5,100 1,403 11,040 Short-term lease cost (2) 893 6,574 5,213 Variable lease cost (3) 1 653 4,513 Total lease expense 25,192 25,927 24,448 Lease costs capitalized — 55 4,127 Total lease costs $ 25,192 $ 25,982 $ 28,575 (1) Represents depreciation and interest associated with financing leases. (2) Represents short term leases under contracts that are 1 year or less where a ROU asset and lease liability are not required to be recorded. (3) Variable costs represent differences between minimum lease costs and actual lease costs incurred under lease contracts. Other information: Year Ended December 31, 2024 2023 2022 Other information: (in thousands) Cash paid for amounts included in the measurement of lease liabilities: Financing cash flows attributable to finance leases (in thousands) $ 10,477 $ 7,161 $ 3,039 Weighted-average remaining lease term (in years) 7.36 8.16 9.65 Weighted-average discount rate 7.16 % 7.99 % 4.59 % Operating cash flows attributable to operating leases (in thousands) $ 2,127 $ 505 $ 19,300 Weighted-average remaining lease term (in years) 4.09 0.67 1.33 Weighted-average discount rate 6.14 % 8.45 % 9.91 % F-38 The table below describes the presentation of the total lease cost on the Company’s consolidated statements of operations and other comprehensive income (loss). As discussed above, the Company’s joint venture owners are required to reimburse the Company for their share of certain expenses, including certain lease costs. Year Ended December 31, 2024 2023 2022 (in thousands) Finance lease cost $ 11,290 $ 10,231 $ 2,188 Production expense 3,517 3,556 12,222 General and administrative expense 346 196 160 Lease costs billed to the joint venture owners 10,039 11,964 11,390 Total lease expense 25,192 25,947 25,960 Lease costs capitalized — 35 2,615 Total lease costs $ 25,192 $ 25,982 $ 28,575 The following table describes the future maturities of the Company’s operating and financing lease liabilities at December 31, 2024: Operating Leases Finance Leases Year (in thousands) 2025 $ 4,368 $ 18,755 2026 4,842 16,674 2027 5,008 15,023 2028 4,780 11,321 2029 520 11,315 Thereafter 220 28,925 19,738 102,013 Less: imputed interest 2,323 21,253 Total lease liabilities $ 17,415 $ 80,760 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. F-39 15. ACCRUED LIABILITIES AND OTHER Accrued liabilities and other balances were comprised of the following: As of December 31 2024 2023 (in thousands) Accrued accounts payable invoices $ 48,913 $ 21,225 State oil liability 19,616 — Capital expenditures 8,923 10,136 Egypt modernization payments 9,933 9,933 Gabon contractual obligations 6,977 15,794 Accrued wages and other compensation 4,956 3,746 Seismic data 2,455 — Asset retirement obligation, current portion 1,174 — Other 4,763 6,763 Total accrued liabilities and other $ 107,710 $ 67,597 16. SHAREHOLDERS ’ EQUITY Dividend Policy The following table is a schedule of dividends paid during 2024: Dividend Payment Date Amount per common share Record Date March 28, 2024 $ 0.0625 March 8, 2024 June 21, 2024 $ 0.0625 May 17, 2024 September 20, 2024 $ 0.0625 August 23, 2024 December 20, 2024 $ 0.0625 November 22, 2024 Aggregate per share amount paid in 2024 $ 0.2500 Preferred stock – Authorized preferred stock consists of 500,000 shares with a par value of $ 25 per share. No shares of preferred stock were issued and outstanding as of December 31, 2024 or 2023. 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. F-40 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 17. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Board of Directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At December 31, 2024, 5,140,880 shares were available for future grants. For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares. As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the years ended December 31, 2024 , 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. Year Ended December 31, 2024 2023 2022 (in thousands) Stock-based compensation - equity awards $ 4,567 $ 3,338 $ 2,045 Stock-based compensation - liability awards ( 9 ) ( 15 ) 155 Total stock-based compensation $ 4,558 $ 3,323 $ 2,200 Stock options and performance shares Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors that is generally a three-year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles. In June 2024 , the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 549,495 shares at an exercise price of $ 5.96 per share and a life of ten years . For each performance stock option award, one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $ 6.85 per share; performance stock options with respect to one-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $ 7.88 per F-41 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. During the year ended December 31, 2024 , 2023 and 2022 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 $ 6.41 Expected life in years 6.7 6.4 6.0 Average expected volatility 71 % 68 % 72 % Risk-free interest rate 4.28 % 3.73 % 1.98 % Expected dividend yield 4.19 % 5.97 % 2.30 % Weighted average grant date fair value - ($/share) $ 3.27 $ 2.29 $ 2.84 Performance stock options activity associated with the Monte Carlo model for the year ended December 31, 2024 is provided below: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (in thousands) (in years) (in thousands) Outstanding at January 1, 2024 611 $ 4.69 Granted 549 5.96 Exercised ( 24 ) 4.54 Unvested shares forfeited ( 18 ) 4.19 Vested shares expired — — Outstanding at December 31, 2024 1,118 $ 5.32 8.6 $ 185 Exercisable at December 31, 2024 228 $ 4.22 7.4 $ 147 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: F-42 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 — $ — 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. Restricted shares Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). The following is the activity for the Company's restricted stock for the year ended December 31, 2024: Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Non-vested shares outstanding at January 1, 2024 1,085 $ 4.50 Awards granted 838 5.96 Awards vested ( 508 ) 4.42 Awards forfeited ( 63 ) 5.14 Non-vested shares outstanding at December 31, 2024 1,352 $ 5.41 The total fair value of vested restricted stock awards during 2024, 2023 and 2022 was $ 5.0 million, $ 1.5 million, and $ 2.4 million, respectively. The weighted average grant date fair value per share of restricted stock awards, which vested during 2024, 2023 and 2022, was $ 4.42 , $ 3.92 and $ 2.25 , 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 F-43 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). 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, 2024 is presented in the table below: Restricted Stock Weighted Average Conversion Date Fair Value (in thousands) Non-vested shares outstanding at January 1, 2024 223 $ 4.22 Awards granted 80 5.96 Awards vested ( 102 ) 4.23 Awards forfeited ( 27 ) 4.20 Non-vested shares outstanding at December 31, 2024 174 $ 5.01 The total fair value of vested RSU awards during 2024 was $ 0.6 million. The weighted average grant date fair value per share of RSU, which vested during 2024, was $ 4.23 . 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. PSUs are similar to RSUs except that they originally contained a performance factor affecting the vesting percentage. For the PSUs that remained outstanding following the effective time of the TransGlobe Acquisition, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200 % for PSUs granted in 2021 and 2022; and 64.4 % for PSUs granted in 2023. 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. F-44 PSU activity for the year ended December 31, 2024 is presented in the table below: Restricted Stock Weighted Average Conversion Date Fair Value (in thousands) Non-vested shares outstanding at January 1, 2024 121 $ 4.27 Awards granted — — Awards vested ( 103 ) 4.27 Awards forfeited ( 9 ) 4.27 Non-vested shares outstanding at December 31, 2024 9 $ 4.27 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. 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, 2024 , there are approximately 101,313 DSUs outstanding, which are vested but not converted. Stock appreciation rights ( “ SARs ” ) SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s Board of Directors. 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 Share (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. 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. On February 28, 2024 , all remaining SAR awards were exercised. F-45 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. In addition, certain named executive officers will receive 75 % of their target bonus. Some of the named executive officers are also entitled to severance payments under their employment agreements. 18. RELATED PARTY TRANSACTIONS 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 amounts in both 2024 and 2023 were primarily for contract engineering services paid to an entity owned and controlled by a related party of an officer of the Company. 19. OTHER COMPREHENSIVE INCOME At December 31, 2024 , the Company’s accumulated other comprehensive loss was $ 5.0 million. All of the Company’s other comprehensive income (loss) arises from the currency translation of VAALCO Energy Canada, Inc. to USD. The components of accumulated other comprehensive income (loss) are as follows: Currency Translation Adjustments (in thousands) Balance at December 31, 2022 $ 1,179 Amounts reclassified from accumulated other comprehensive income (loss) 1,701 Balance at December 31, 2023 $ 2,880 Amounts reclassified from accumulated other comprehensive income (loss) ( 7,842 ) Balance at December 31, 2024 $ ( 4,962 ) 20. 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. F-46 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. SUPPLEMENTAL INFORMATION ON CRUDE OIL, NATURAL GAS AND NGLs PRODUCING ACTIVITIES (UNAUDITED) This supplemental information is presented in accordance with certain provisions of ASC Topic 932 – Extractive Activities- Oil and Natural Gas . 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. Costs Incurred for Acquisition, Exploration and Development Activities Costs incurred during the year: Gabon Egypt Canada Cote d'Ivoire Total Year Ended December 31, 2024 (1) (in thousands) Exploration costs - expensed $ — $ 48 $ — $ — $ 48 Acquisition of properties — — — 107,089 107,089 Development costs 22,579 11,364 25,828 44,435 104,205 Total $ 22,579 $ 11,412 $ 25,828 $ 151,524 $ 211,342 Gabon Egypt Canada Total Year Ended December 31, 2023 (in thousands) Exploration costs - expensed $ 51 $ 1,914 $ — $ 1,965 Acquisition of properties — — — — Development costs 17,011 37,866 16,809 71,686 Total $ 17,062 $ 39,780 $ 16,809 $ 73,651 Gabon Egypt Canada Total Year Ended December 31, 2022 (2) (in thousands) Exploration costs - capitalized $ 47 $ — $ — $ 47 Exploration costs - expensed 258 — — 258 Acquisition of properties — 170,982 104,390 275,372 Development costs 162,328 7,515 2,187 172,030 Total $ 162,633 $ 178,497 $ 106,577 $ 447,707 (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. F-47 Capitalized Costs Relating to crude oil, natural gas and NGLs Producing Activities Capitalized costs pertain to the producing activities in Gabon, Egypt, Cote d'Ivoire and Canada and to undeveloped leasehold in Gabon, Egypt, Cote d'Ivoire, Canada and Equatorial Guinea. As of December 31, 2024 2023 Capitalized costs: (in thousands) Properties not being amortized $ 155,825 $ 79,406 Properties being amortized 1,588,699 1,467,039 Total capitalized costs $ 1,744,524 $ 1,546,445 Less accumulated depletion, amortization and impairment (1,214,465) (1,091,910) Net capitalized costs $ 530,059 $ 454,535 Results of Operations for crude oil, natural gas and NGLs Producing Activities Gabon Egypt Canada Cote d'Ivoire Total Year Ended December 31, 2024 (2) (In thousands) Revenues $ 205,954 $ 145,966 $ 31,986 $ 95,082 $ 478,988 Production costs and other expense (1) (62,234) (50,770) (11,301) (38,017) (162,322) Depreciation, depletion, amortization (50,679) (33,458) (19,309) (38,771) (142,217) Exploration expenses — (48) — — (48) Other operating expense (24) — 102 — 78 Income tax benefit (expense) (80,488) (34,300) — (2,587) (117,375) Results from crude oil and natural gas producing activities $ 12,529 $ 27,390 $ 1,478 $ 15,707 $ 57,104 Gabon Egypt Canada Total Year Ended December 31, 2023 (In thousands) Crude oil and natural gas sales $ 260,346 $ 161,049 $ 33,671 $ 455,066 Production costs and other expense (1) (94,615) (54,779) (9,463) (158,857) Depreciation, depletion, amortization (62,622) (35,095) (17,398) (115,115) Exploration expenses (51) (1,914) — (1,965) Other operating expense (55) (241) 729 433 Income tax benefit (expense) (67,982) (37,271) — (105,253) Results from crude oil and natural gas producing activities $ 35,021 $ 31,749 $ 7,539 $ 74,309 Gabon Egypt Canada Total Year Ended December 31, 2022 (3) (In thousands) Crude oil and natural gas sales $ 306,775 $ 37,710 $ 9,841 $ 354,326 Production costs and other expense (1) (108,701) (11,936) (1,972) (122,609) Depreciation, depletion, amortization (34,651) (10,444) (2,921) (48,016) Exploration expenses (258) — — (258) Other operating expense 38 — — 38 Credit (recovery) losses and other (2,743) — — (2,743) Income tax benefit (expense) (16,641) (6,254) — (22,895) Results from crude oil and natural gas producing activities $ 143,819 $ 9,076 $ 4,948 $ 157,843 (1) Includes local general and administrative expenses but excludes corporate general and administrative expenses and allocated corporate overhead. (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. F-48 Estimated Quantities of Proved Reserves The estimation of net recoverable quantities of crude oil, natural gas and NGLs is a highly technical process that is based upon several underlying assumptions that are subject to change. See “ Item 1A. Risk Factors ” and “ Item 7. Management ’ s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Critical Accounting Policies and Estimates – Successful Efforts Method of Accounting for crude oil, natural gas and NGLs Activities. ” For a discussion of the reserve estimation process, including internal controls, see “ Item 1. Business – Reserve Information .” Oil Proved reserves: Gabon (MBbls) Egypt (MBbls) Canada (MBbls) Cote d'Ivoire (MBbls) Total (MBbls) Balance at January 1, 2022 11,218 — — — 11,218 Production (2,971) (547) (72) — (3,590) Purchase of reserves — 9,124 3,679 — 12,803 Extensions and discoveries — — — — — Revisions of previous estimates 1,972 — — — 1,972 Balance at December 31, 2022 10,219 8,577 3,607 — 22,403 Production (3,197) (2,771) (334) — (6,302) Purchase of reserves — — — — — Extensions and discoveries — 93 810 — 903 Revisions of previous estimates 2,042 4,693 (652) — 6,083 Balance at December 31, 2023 9,064 10,592 3,431 — 23,087 Production (2,783) (2,585) (348) (1,054) (6,770) Purchase of reserves — — — 15,288 15,288 Extensions and discoveries — — (93) — (93) Revisions of previous estimates 4,782 1,441 (225) 1,018 7,016 Balance at December 31, 2024 11,063 9,448 2,765 15,252 38,528 Oil Gabon (MBbls) Egypt (MBbls) Canada (MBbls) Cote d'Ivoire (MBbls) Total (MBbls) Year-end proved developed reserves: 2024 6,830 8,962 1,480 118 17,390 2023 8,053 10,141 1,309 — 19,503 2022 10,219 8,001 1,722 — 19,942 2021 7,227 — — — 7,227 Year-end proved undeveloped reserves: 2024 4,233 486 1,286 15,134 21,139 2023 1,011 451 2,122 — 3,584 2022 — 576 1,885 — 2,461 2021 3,991 — — — 3,991 F-49 Natural Gas Proved reserves: Gabon (MMcf) Egypt (MMcf) Canada (MMcf) Cote d'Ivoire (MMcf) Total (MMcf) Balance at December 31, 2022 — — 16,539 — 16,539 Production — — (1,528) — (1,528) Purchase of reserves — — — — — Extensions and discoveries — — 3,219 — 3,219 Revisions of previous estimates — — (1,298) — (1,298) Balance at December 31, 2023 — — 16,932 — 16,932 Production — — (1,532) (26) (1,558) Purchase of reserves — — — 6,830 6,830 Extensions and discoveries — — 234 — 234 Revisions of previous estimates — — 446 (253) 193 Balance at December 31, 2024 — — 16,080 6,551 22,631 Natural Gas Gabon (MMcf) Egypt (MMcf) Canada (MMcf) Cote d'Ivoire (MMcf) Total (MMcf) Year-end proved developed reserves: 2024 — — 10,490 47 10,537 2023 — — 9,011 — 9,011 2022 — — 11,023 — 11,023 Year-end proved undeveloped reserves: 2024 — — 5,590 6,504 12,094 2023 — — 7,921 — 7,921 2022 — — 5,516 — 5,516 NGLs Proved reserves: Gabon (MBbls) Egypt (MBbls) Canada (MBbls) Cote d'Ivoire (MBbls) Total (MBbls) Balance at December 31, 2022 — — 2,797 — 2,797 Production — — (270) — (270) Purchase of reserves — — — — — Extensions and discoveries — — 505 — 505 Revisions of previous estimates — — (295) — (295) Balance at December 31, 2023 — — 2,737 — 2,737 Production — — (267) — (267) Purchase of reserves — — — — — Extensions and discoveries — — 40 — 40 Revisions of previous estimates — — 170 — 170 Balance at December 31, 2024 — — 2,680 — 2,680 F-50 NGLs Gabon (MBbls) Egypt (MBbls) Canada (MBbls) Cote d'Ivoire (MBbls) Total (MBbls) Year-end proved developed reserves: 2024 — — 1,744 — 1,744 2023 — — 1,449 — 1,449 2022 — — 1,855 — 1,855 Year-end proved undeveloped reserves: 2024 — — 936 — 936 2023 — — 1,289 — 1,289 2022 — — 942 — 942 Total Reserves (1) Proved reserves: Gabon (MBoe) Egypt (MBoe) Canada (MBoe) Cote d'Ivoire (MBoe) Total (MBoe) Balance at January 1, 2022 11,218 — — — 11,218 Production (2,971) (547) (211) — (3,729) Extensions and discoveries — — — — — Purchase of reserves — 9,124 9,372 — 18,496 Revisions of previous estimates 1,972 — — — 1,972 Balance at December 31, 2022 10,219 8577 9161 — 27,957 Production (3,197) (2,771) (859) — (6,827) Extensions and discoveries — — — — — Purchase of reserves — 93 1,852 — 1,945 Revisions of previous estimates 2,042 4,693 (1,163) — 5,572 Balance at December 31, 2023 9,064 10,592 8,991 — 28,647 Production (2,783) (2,585) (870) (1,058) (7,296) Purchase of reserves — — — 16,465 16,465 Extensions and discoveries — — (14) — (14) Revisions of previous estimates 4,782 1,441 19 974 7,216 Balance at December 31, 2024 11,063 9,448 8,126 16,381 45,018 (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. Total Reserves (1) Gabon (MBoe) Egypt (MBoe) Canada (MBoe) Cote d'Ivoire (MBoe) Total (MBoe) Year-end proved developed reserves: 2024 6,830 8,962 4,972 126 20,890 2023 8,053 10,141 4,260 — 22,454 2022 10,219 8,001 5,414 — 23,634 2021 7,227 — — — 7,227 Year-end proved undeveloped reserves: 2024 4,233 486 3,154 16,255 24,128 2023 1,011 451 4,731 — 6,193 2022 — 576 3,746 — 4,322 2021 3,991 — — — 3,991 (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. 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 F-51 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. 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. 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. 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. Additionally, the development plan is required to have the approval of the joint venture owners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the block, this approval must have been received prior to booking any reserves. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Crude Oil Reserves The information that follows has been developed pursuant to procedures prescribed under GAAP and uses reserve and production data estimated by independent petroleum consultants. The information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating its or the Company’s performance. F-52 In accordance with the guidelines of the SEC, the estimates of future net cash flow from the properties and the present value thereof are made using crude oil, natural gas and NGLs contract prices using a twelve month average of beginning of month prices and 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. The future cash flows are also based on costs in existence at the dates of the projections, excluding Gabon royalties, and the interests of other Consortium members. Future production costs do not include overhead charges allowed under joint operating agreements or headquarters general and administrative overhead expenses. However, all future costs related to future property abandonment when the wells become uneconomic to produce are included in future development costs for purposes of calculating the standardized measure of discounted net cash flows. There were no discounted future net cash flows attributable to U.S. properties as of December 31, 2024, 2023 and 2022. International (In thousands) Gabon Egypt Canada Cote d'Ivoire Total Year Ended December 31, 2024 Future cash inflows $ 912,914 $ 782,814 $ 269,195 $ 1,423,441 $ 3,388,364 Future production costs (470,775) (370,085) (123,367) (446,645) (1,410,872) Future development costs (1) (221,743) (93,426) (62,629) (466,407) (844,205) Future income tax expense (134,216) (144,883) — (205,167) (484,266) Future net cash flows 86,180 174,420 83,199 305,222 649,021 Discount to present value at 10% annual rate (13,169) (39,281) (36,092) (181,079) (269,621) Standardized measure of discounted future net cash flows $ 73,011 $ 135,139 $ 47,107 $ 124,143 $ 379,400 Year Ended December 31, 2023 Future cash inflows $ 761,919 $ 828,418 $ 352,666 $ — $ 1,943,003 Future production costs (410,425) (383,957) (129,317) — (923,699) Future development costs (1) (88,868) (84,132) (80,129) — (253,129) Future income tax expense (148,750) (144,269) — — (293,019) Future net cash flows 113,876 216,060 143,220 — 473,156 Discount to present value at 10% annual rate (6,052) (54,313) (70,857) — (131,222) Standardized measure of discounted future net cash flows $ 107,824 $ 161,747 $ 72,363 $ — $ 341,934 Year Ended December 31, 2022 Future cash inflows $ 1,035,667 $ 729,236 $ 506,247 $ — $ 2,271,150 Future production costs (450,639) (273,260) (135,082) — (858,981) Future development costs (1) (58,057) (12,079) (69,346) — (139,482) Future income tax expense (248,024) (146,835) — — (394,859) Future net cash flows 278,947 297,062 301,819 — 877,828 Discount to present value at 10% annual rate (34,520) (70,174) (148,669) — (253,363) Standardized measure of discounted future net cash flows $ 244,427 $ 226,888 $ 153,150 $ — $ 624,465 (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). F-53 Changes in Standardized Measure of Discounted Future Net Cash Flows The following table sets forth the changes in standardized measure of discounted future net cash flows as follows: Year Ended December 31, 2024 2023 2022 (in thousands) Balance at beginning of period $ 341,934 $ 624,465 $ 99,258 Sales of crude oil and natural gas, net of production costs (316,667) (296,209) (233,421) Net changes in prices and production costs 19,018 (210,703) 264,804 Extensions and discoveries 8,318 28,849 — Revisions of previous quantity estimates 144,956 139,856 95,623 Purchases 175,849 — 415,385 Changes in estimated future development costs (94,004) (92,641) (23,243) Development costs incurred during the period 28,676 — 101,495 Accretion of discount 45,917 62,447 9,926 Net change of income taxes 21,053 77,757 (121,490) Change in production rates (timing) and other 4,350 8,113 16,128 Balance at end of period $ 379,400 $ 341,934 $ 624,465 There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated crude oil, natural gas and NGLs reserves attributable to the properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown for Gabon are recoverable under a service contract and the reserves in place at the end of the contract period remain the property of the Gabon government. In accordance with the current SEC guidelines, estimates of future net cash flow from our properties and the present value thereof are made using the average of the first-day-of-the-month price for each of the twelve months of the year adjusted for quality, transportation fees and market differentials. 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: Year Ended December 31, 2024 2023 Crude Oil ($/Bbl) Gabon $ 81.08 $ 83.22 Egypt $ 65.48 $ 64.59 Cote d'Ivoire $ 79.70 $ — Canada $ 69.12 $ 71.67 F-54 For 2024 and 2023, the adjusted average prices for our reserves associated with natural gas and NGLs were as follows: Year Ended December 31, 2024 2023 Cote d'Ivoire Natural Gas ($/Mcf) $ 2.77 $ — Canada Natural Gas ($/Mcf) $ 0.95 $ 1.91 Canada Ethane ($/Bbl) $ 3.52 $ 5.20 Propane ($/Bbl) $ 19.46 $ 20.18 Butane ($/Bbl) $ 30.68 $ 36.69 Condensates ($/Bbl) $ 69.59 $ 74.76 Production Sharing Contracts Under the Etame PSC in Gabon, the Gabonese government is the owner of all crude oil, natural gas and NGLs mineral rights. The right to produce the crude oil, natural gas and NGLs is stewarded by the Directorate Generale de Hydrocarbures and the Etame PSC was awarded by a decree. Pursuant to the contract, the Gabon government receives a fixed royalty rate of 13%. Originally, under the Etame PSC, Gabonese government was not anticipated to take physical delivery of its allocated production. 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). 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”). Prior to the PSC Extension, the Consortium was entitled to a 70% Cost Recovery Percentage. Under the PSC Extension, the Cost Recovery Percentage is increased to 80% for the ten-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%. As payment of corporate income taxes, the Etame Consortium pays the government an allocation of the remaining Profit Oil production from the contract area ranging from 50% to 60% of the crude oil remaining after deducting the royalty and Cost Recovery. The percentage of Profit Oil paid to the government as tax is a function of production rates. However, when the Cost Account becomes substantially recovered, the Company only recovers ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. Also because of the nature of the Cost Account, decreases in crude oil prices result in a higher number of barrels required to recover costs. The Etame PSC allows for exploitation period through the carve-out of development areas, which include all producing fields in the Etame Marin block as well as additional undeveloped areas where reserves may exist. The PSC Extension extends the term for each of the three exploitation areas in the Etame Marin block for a period of ten years with effect from September 17, 2018, the effective date of the PSC Extension. The PSC Extension also grants the Etame Consortium the right for two additional extension periods of five years each. This compares to the economic end date of reserves under the current reserve report evaluated by the independent reserve engineering firm of Netherland, Sewell & Associates, Inc. The PSC for Block P in Equatorial Guinea entitles the Company to receive up to 70% of any future production after royalty deduction so long as there are amounts remaining in the Cost Account. Royalty rates are 10-16% depending on production rates. The Etame Consortium pays the government an allocation of the remaining Profit Oil production from the contract area ranging from 10% to 60% of the crude oil remaining after deducting the royalty and Cost Recovery. The percentage of Profit Oil paid to the government as tax is a function of cumulative production. 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. At December 31, 2024, the Company has no SEC proved reserves related to Block P in Equatorial Guinea. Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (Cost Oil or cost recovery barrels) which are assigned 100% to the Company. 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 F-55 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”. In Egypt, depending on the PSCs, the Contractor's share of excess ranges between 5% and 15%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum Cost Oil ranges from 25% to 40% in Egypt. The balance of the production after maximum cost recovery is shared with the government (Profit Oil). Depending on the contract, the Egyptian government receives 67% to 84% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Under the Modernized Royalty Framework (the “MRF”) in Alberta, producers initially pay a flat royalty of 5% on production revenue from each producing well until payout, which is the point at which cumulative gross revenues from the well equals the applicable drilling and completion cost allowance. After payout, producers pay an increased royalty of up to 40% that will vary depending on the nature of the resource and market prices. Once the rate of production from a well is too low to sustain the full royalty burden, its royalty rate is gradually adjusted downward as production declines, eventually reaching a floor of 5%. The MRF applies to the hydrocarbons produced by wells spud or re-entered on or after January 1, 2017. The Royalty Guarantee Act (Alberta) came into effect in July 2019, amending the Mines and Minerals Act (Alberta) and guaranteeing no major changes to the oil and gas royalty structure for a period of 10 years. Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner. The Government of Alberta levies annual freehold mineral taxes for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties and is payable by the registered owner of the mineral rights. 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”). Under the Cote d'Ivoire PSC, the Company is entitled to a Cost Oil recovery percentage of up to 80% of total production. Profit Oil percentage ranges from 30% to 53% based on the range of daily total production. Cost Oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the government state oil company. Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the government of Cote d'Ivoire. In addition, under the terms of the Cote d'Ivoire PSC, the tax payments to the Ivorian Government are deemed satisfied by its share of the Profit Oil. F-56