Item 9A. Controls and Procedures
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 effective as of December 31, 2025.
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. The Company’s management, with participation of the CEO and CFO, under the oversight of our Board of Directors, evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025 using the COSO framework. Based on the evaluation, our management concluded that, the Company’s internal control over financial reporting was effective as of December 31, 2025.
Remediation of Prior Material Weaknesses
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.
70
Table of Contents
As discussed in our Annual Report on Form 10-K for the year ended December 31, 2024, our management concluded that there were material weaknesses in our internal control over financial reporting related to general information technology controls, effectiveness of control environment, risk assessment and design and process-level controls.
In response to the identified material weakness at December 31, 2024, our management, with oversight from our Audit Committee, made the following changes in its financial reporting processes in 2025:
• We strengthened IT controls by adding resources and reallocating staff to improve risk assessment, change management, and IT oversight.
• We enhanced our efforts to design and implement a continuous risk-assessment process to identify and address risks of material misstatement and to ensure controls are properly designed and operating effectively.
• We established and implemented a comprehensive risk assessment process over general information technology controls, which continues to be refined as part of our ongoing monitoring activities.
• We hired a new IT Director and management has reviewed IT general controls with the IT Director to provide visibility into control design and align responsibilities for ongoing monitoring of controls.
After completing our testing of the design and operational effectiveness of these controls, our management concluded that we fully remediated the previously identified material weaknesses as of December 31, 2025.
Our internal controls over financial reporting as of December 31, 2025 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this Annual Report. KPMG LLP has provided an attestation report on the Company’s internal control over financial reporting which is included in Item 8 of this Annual Report.
Changes in Internal Control over Financial Reporting
Other than as stated above, no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B . Other Information
During the quarter ended December 31, 2025 , none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted , terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act).
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 2026 annual meeting, which will be filed with the SEC within 120 days of December 31, 2025, 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 2026 annual meeting, which will be filed with the SEC within 120 days of December 31, 2025, 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 2026 annual meeting, which will be filed with the SEC within 120 days of December 31, 2025, and which is incorporated herein by reference.
71
Table of Contents
The following table provides information as of December 31, 2025 regarding the number of shares of common stock that may be issued under our compensation plans. Please refer to Part IV, Item 15., Note 16. 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 1,097,482 $ 5.30 483,624
Total 1,097,482 $ 5.30 483,624
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be included in our proxy statement for our 2026 annual meeting, which will be filed with the SEC within 120 days of December 31, 2025, 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 2026 annual meeting, which will be filed with the SEC within 120 days of December 31, 2025, and that is incorporated herein by reference.
72
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 Over Internal Controls over Financial Reporting (KPMG LLP; Houston, Texas; PCAOB ID No. 185)
F - 4
Consolidated Balance Sheets as of December 31, 202 5 and 202 4
F - 5
Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 202 5 , 202 4 and 202 3
F - 6
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 202 5 , 202 4 and 202 3
F - 7
Consolidated Statements of Cash Flows for the Years Ended December 31, 202 5 , 202 4 and 202 3
F - 8
Notes to the Consolidated Financial Statements
F - 10
Supplemental Information on Crude Oil, Natural Gas and NGLs Producing Activities (Unaudited)
F - 46
(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).
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).
73
Table of Contents
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).
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).
74
Table of Contents
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)
10. 30 **
Crude Oil Sale and Marketing Agreement, by and between VA ALCO Gabon S.A. and Glencore Energy UK Ltd., dated May 20, 2022 (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on August 10, 2022, and incorporated herein by reference).
10.3 1 *
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) .
75
Table of Contents
10. 31 .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).
10.3 2 *
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) .
10.3 2. 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).
10.33 **
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 (filed as Exhibit 10.34 to the Company’s Annual Report on Form 10-K filed on March 17, 2025 and incorporated herein by reference) .
10.34 *
Form of 2025 Restricted Stock Award Agreement under the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on August 11, 2025, and incorporated herein by reference).
10.35 **
Asset Purchase Agreement, by and among VAALCO Energy Canada, Inc., Petrus Resources Corp., and, solely for the purposes of Section 9.7 therein, Petrus Resources LTD., dated February 4, 2026. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 10, 2026, and incorporated herein by reference).
19.1
Insider Trading Policy (filed as Exhibit 19.1 to the Company’s Annual Report on Form 10-K filed on March 17, 2025 and incorporated herein by reference).
21.1 (a)
List of subsidiaries of the Company.
23.1 (a)
Consent of KPMG LLP
23.2 (a)
Consent of Netherland, Sewell & Associates, Inc. — 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
Clawback Policy (filed as Exhibit 97.1 to the Company’s Annual Report on Form 10-K filed on March 17, 2025 and incorporated herein by reference).
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 Netherland, Sewell & Associates, Inc. (International Properties) - Canada
101.INS(a) Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
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.
Item 16. Form 10-K Summary
None.
76
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 16, 2026
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the 16th day of March 2026, 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
77
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, 2025 and 2024, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 16, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
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, natural gas and NGLs properties
As discussed in Note 2 to the consolidated financial statements, the Company determines depletion of crude oil, natural gas and NGLs properties on a block basis under the unit-of-production method based upon estimates of proved reserves. For the year ended December 31, 2025, the Company recorded depreciation, depletion and amortization expense of $110 million. 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, natural gas and NGLs properties as a critical audit matter. Changes in assumptions used to estimate the proved reserves could have had a significant impact on depletion expense. Complex auditor judgment was required in evaluating the Company’s estimates of proved reserves. Specifically, auditor judgment was required to evaluate the assumptions used by the Company related to future production and future operating and capital costs.
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 firm engaged by the Company. We evaluated the relationship of the independent reserve engineer specialists and independent reserve engineering firm to the Company. We analyzed and assessed the determination of depletion expense for compliance with industry and regulatory standards. We assessed compliance of the methodology used by the Company’s independent reserve engineer specialists to estimate proved reserves with industry and regulatory standards. We read and considered the report of the Company’s independent reserve engineering firm in connection with our evaluation of the Company’s proved reserve estimates. We compared future production to historical production rates. We evaluated the future operating and capital costs by comparing them to historical costs.
Evaluation of the recoverability of certain crude oil, natural gas and NGLs producing properties
As discussed in Note 2 to the consolidated financial statements, the Company performs impairment tests with respect to its crude oil, natural gas and NGLs producing properties on an asset group basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If there is an indication the carrying amount of the crude oil, natural gas and NGLs producing properties may not be recovered, the Company estimates the undiscounted future net cash flows and compares this to the carrying value of the crude oil and natural gas property. If the sum of the expected undiscounted future net cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. Estimated future net cash flows are based on assumptions such as forecasted production, forecasted commodity prices inclusive of price differentials, and development and operating costs. As a result of these tests, no impairments were recorded during the year ended December 31, 2025 for the Company’s crude oil, natural gas and NGLs producing properties, excluding properties held for sale.
We identified the evaluation of the estimate of undiscounted future net cash flows from the related proved and probable reserves, used to assess the recoverability of certain crude oil and natural gas producing properties, as a critical audit matter. Subjective auditor judgment was required in the evaluation of the estimate of undiscounted future net cash flows from the related proved and probable reserves, due to (1) uncertainty associated with future commodity prices and estimated future production, (2) judgment inherent in forecasting development and operating costs, and (3) subjectivity in determining the risk adjustment factors associated with reserve volumes.
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 impairment of crude oil, natural gas and NGLs producing properties process, including controls over the Company’s proved and probable reserve estimation process. We evaluated the professional qualifications and knowledge, skills, and ability of the Company’s internal reserve engineers, the independent reserve engineer specialists, and the independent reserve engineering firm engaged by the Company. We evaluated the relationships of the independent reserve engineer specialists and independent reserve engineering firm to the Company. We analyzed and assessed the estimate of undiscounted future net cash flows from the related proved and probable reserves for compliance with industry and regulatory standards. We assessed compliance of the methodology used by the Company’s independent reserve engineer specialists to estimate proved and probable reserves with industry and regulatory standards. We read and considered the report of the Company’s independent reserve engineering firm in connection with our evaluation of the Company’s proved and probable reserves estimate. We evaluated the Company’s undiscounted future net cash flows analysis related to forecasted production, and development and operating costs by comparing to historical results and future development plans. We evaluated the relevant price differentials used by the Company by comparing them to historical results. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the forecasted commodity prices, by comparing them to an independently developed range of forward price estimates using data from analysts and other industry sources, and the risk adjustment factors associated with reserve volumes, by comparing them to third party publications of risk adjustment factors utilized by market participants.
/s/ KPMG LLP
We have served as the Company’s auditor since 2023.
Houston, Texas
March 16, 2026
F-3
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, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated March 16, 2026 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
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.
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 16, 2026
F-4
VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31,
(in thousands, except share amounts) 2025 2024
ASSETS
Current assets:
Cash and cash equivalents $ 58,900 $ 82,650
Restricted cash 136 143
Receivables:
Trade, net of allowances for credit loss and other of $ 0.0 million and $ 0.2 million, respectively
39,924 94,778
Accounts with joint venture owners, net of allowance for credit losses of $ 2.7 million and $ 1.5 million, respectively
5,420 179
Egypt receivables and other 2,277 35,763
Crude oil inventory 1,774 9,441
Prepayments and other 24,370 14,973
Current assets held for sale 179 —
Total current assets 132,980 237,927
Crude oil, natural gas and NGLs properties and equipment, net 586,095 538,103
Other noncurrent assets:
Restricted cash 1,659 8,665
Value added tax and other receivables, net of allowances for credit loss and other of $ 0.0 million and $ 0.8 million, respectively
7,149 10,094
Right of use operating lease assets 16,596 17,254
Right of use finance lease assets 68,615 79,849
Deferred tax assets 54,825 55,581
Abandonment funding 6,268 6,268
Other long-term assets 7,362 1,209
Noncurrent assets held for sale 31,826 —
Total assets $ 913,375 $ 954,950
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 44,661 $ 11,756
Accounts with joint venture owners 3,193 3,324
Accrued liabilities and other 106,444 107,710
Operating lease liabilities - current portion 5,744 3,512
Finance lease liabilities - current portion 12,119 13,383
Foreign income taxes payable 19,656 42,043
Current liabilities held for sale 183 —
Total current liabilities 192,000 181,728
Asset retirement obligations 78,406 78,592
Operating lease liabilities - net of current portion 11,183 13,903
Finance lease liabilities - net of current portion 57,256 67,377
Deferred tax liabilities 63,630 93,904
Long-term debt 60,000 —
Other long-term liabilities — 17,863
Noncurrent liabilities held for sale 7,403 —
Total liabilities 469,878 453,367
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock, $ 25 par value; 500,000 shares authorized, none issued
— —
Common stock, $ 0.10 par value; 160,000,000 shares authorized, 123,017,656 and 122,304,124 shares issued, 104,258,253 and 103,743,163 shares outstanding, respectively
12,302 12,230
Additional paid-in capital 368,536 362,578
Accumulated other comprehensive loss ( 498 ) ( 4,962 )
Less treasury stock, 18,759,403 and 18,560,931 shares, respectively, at cost
( 78,733 ) ( 78,024 )
Retained earnings 141,890 209,761
Total shareholders' equity 443,497 501,583
Total liabilities and shareholders' equity $ 913,375 $ 954,950
See notes to consolidated financial statements.
F-5
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
Year Ended December 31,
2025 2024 2023
(in thousands, except per share amounts)
Revenues:
Crude oil, natural gas and natural gas liquids sales $ 359,272 $ 478,988 $ 455,066
Operating costs and expenses:
Production expense 158,177 163,500 153,157
FPSO demobilization and other costs — — 7,484
Exploration expense 8,914 48 1,965
Depreciation, depletion and amortization 109,978 143,034 115,302
Impairment loss on assets held for sale 67,224 — —
General and administrative expense 33,089 29,684 23,840
Credit losses (recovery) and other 106 6,304 ( 4,906 )
Total operating costs and expenses 377,488 342,570 296,842
Other operating income (expense), net ( 2,391 ) 78 433
Operating income (loss) ( 20,607 ) 136,496 158,657
Other income (expense):
Derivative instruments gain (loss), net 2,876 ( 745 ) 232
Interest expense, net ( 8,243 ) ( 3,732 ) ( 6,452 )
Bargain purchase gain and measurement period adjustment — 13,532 ( 1,412 )
Other expense, net ( 595 ) ( 5,754 ) ( 894 )
Total other income (expense), net ( 5,962 ) 3,301 ( 8,526 )
Income (loss) before income taxes ( 26,569 ) 139,797 150,131
Income tax expense 14,822 81,307 89,777
Net income (loss) $ ( 41,391 ) $ 58,490 $ 60,354
Other comprehensive income (loss)
Currency translation adjustments 4,464 ( 7,842 ) 1,701
Comprehensive income (loss) $ ( 36,927 ) $ 50,648 $ 62,055
Basic net income (loss) per share:
Net income (loss) per share $ ( 0.40 ) $ 0.56 $ 0.56
Basic weighted average shares outstanding 104,055 103,669 106,376
Diluted net income (loss) per share:
Net income (loss) per share $ ( 0.40 ) $ 0.56 $ 0.56
Diluted weighted average shares outstanding 104,055 103,747 106,555
See notes to consolidated financial statements
F-6
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, 2023 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
Shares issued - stock-based compensation 714 — 72 ( 72 ) — — — —
Stock-based compensation expense — — — 6,030 — — — 6,030
Treasury stock — ( 198 ) — — — ( 709 ) — ( 709 )
Dividend distributions — — — — — — ( 26,480 ) ( 26,480 )
Other comprehensive income — — — — 4,464 — — 4,464
Net income (loss) — — — — — — ( 41,391 ) ( 41,391 )
Balance at December 31, 2025 123,018 ( 18,759 ) $ 12,302 $ 368,536 $ ( 498 ) $ ( 78,733 ) $ 141,890 $ 443,497
See notes to consolidated financial statements.
F-7
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2025 2024 2023
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ ( 41,391 ) $ 58,490 $ 60,354
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 109,978 143,034 115,302
Bargain purchase gain and measurement period adjustment — ( 13,532 ) 1,412
Impairment loss on assets held for sale 67,224 — —
Non-cash exploration expense 2,409 48 1,841
Deferred taxes ( 29,427 ) ( 16,785 ) ( 2,864 )
Stock-based compensation 6,211 4,281 2,945
Derivative instruments loss, net ( 2,876 ) 745 ( 232 )
Cash settlements paid on matured derivative contracts, net ( 48 ) ( 453 ) ( 127 )
Cash settlements paid on asset retirement obligations ( 225 ) ( 368 ) ( 6,747 )
Credit losses and other ( 164 ) 6,346 7,650
Equipment and other expensed in operations 5,572 2,505 3,196
Change in operating assets and liabilities:
Trade receivables, net 45,012 ( 49,890 ) 6,723
Accounts with joint venture owners, net 47 ( 757 ) 19,571
Egypt receivables and other, net 32,427 5,644 14,802
Crude oil inventory 7,667 7,488 1,387
Prepayments and other ( 11,697 ) ( 4,817 ) 4,743
Value added tax and other receivables 7,042 ( 7,110 ) 2,427
Other long-term assets 1,161 2,869 3,830
Accounts payable 50,907 ( 13,198 ) ( 28,102 )
Foreign income taxes receivable (payable) ( 22,456 ) 22,682 22,030
Accrued liabilities and other ( 14,706 ) ( 33,504 ) ( 6,544 )
Net cash provided by operating activities 212,667 113,718 223,597
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures, including exploration expense ( 252,856 ) ( 102,996 ) ( 97,223 )
Acquisition of crude oil and natural gas properties ( 3,034 ) 877 —
Net cash used in investing activities ( 255,890 ) ( 102,119 ) ( 97,223 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock — 447 673
Proceeds from borrowings 60,000 — —
Dividend distribution ( 26,480 ) ( 26,216 ) ( 26,772 )
Treasury shares ( 709 ) ( 6,802 ) ( 23,570 )
Deferred financing costs ( 7,145 ) — —
Payments of finance lease ( 13,289 ) ( 10,477 ) ( 7,150 )
Net cash used in in financing activities 12,377 ( 43,048 ) ( 56,819 )
Effects of exchange rate changes on cash 83 ( 3 ) ( 153 )
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH ( 30,763 ) ( 31,452 ) 69,402
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD 97,726 129,178 59,776
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD $ 66,963 $ 97,726 $ 129,178
See notes to consolidated financial statements.
F-8
VAALCO ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES
Year Ended December 31,
2025 2024 2023
(in thousands)
Supplemental disclosure of cash flow information:
Income taxes paid in-kind with crude oil $ 33,714 $ 37,469 $ 32,776
Interest paid, net of amounts capitalized $ 6,637 $ 6,714 $ 9,122
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period $ 8,190 $ 9,479 $ 14,137
Recognition of right-of-use operating lease assets and liabilities $ 3,343 $ 17,649 $ 2,582
Recognition of right-of-use finance lease assets and liabilities $ 2,372 $ — $ 7,875
Asset retirement obligations adjustments $ 85 $ 27,424 $ 2,487
See notes to consolidated financial statements.
F-9
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 portfolio of production development and exploration assets located in Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea, Nigeria, as well as, prior to the Canada Asset Divestment (defined below), producing properties in Canada.
2 . SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation – The accompanying consolidated financial statements (“Financial Statements”) include the accounts of the Company and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating and non-operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation.
Use of estimates – The preparation of the Financial Statements in conformity with generally accepted accounting principles in the U.S. (“GAAP”) requires estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
Estimates of crude oil, natural gas and NGLs reserves used to estimate depletion expense and impairment charges, as well as to estimate the fair value of assets and liabilities acquired in business combinations, require significant judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information becomes available.
Cash and cash equivalents – Cash and cash equivalents includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks associated with cash and cash equivalents.
Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and estimated timing of usage. As of December 31, 2025, the balance in current restricted cash is for employee-related payroll withholdings, while the long-term restricted cash account represents the funding requirement for the debt service reserve account (“DSRA”) under the 2025 RBL Facility. The DSRA required balance is calculated based on the aggregate amount of scheduled principal payable by the Company and the amount of interest payable outstanding under the 2025 RBL Facility. As of December 31, 2024, the balance in current restricted cash is for an escrow amount representing bank guarantees for customs clearance in Gabon and employee-related payroll withholdings, while the long-term restricted cash includes the balance for charter payment escrow for the FPSO offshore Gabon. In addition, the long-term account also includes an $ 8.9 million balance for the settlement of a tax audit related to the Svenska Acquisition with a corresponding accrued tax settlement liability recorded and included in Other long-term liabilities in the Consolidated Balance Sheet.
In the first quarter of 2023 , the Directorate of Hydrocarbons in Gabon approved a $ 26.6 million ($ 15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $ 15.6 million in March 2023 . The remaining balance of the abandonment fund was unchanged during 2025 .
F-10
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,
2025 2024
(in thousands)
Cash and cash equivalents $ 58,900 $ 82,650
Restricted cash - current 136 143
Restricted cash - non-current 1,659 8,665
Abandonment funding 6,268 6,268
Total cash, cash equivalents and restricted cash $ 66,963 $ 97,726
Trade, net – The Company’s trade accounts receivable results from sales of crude oil, natural gas and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses and other below.
Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements. For credit loss and other allowances associated with accounts with joint venture owners, see allowance for credit loss and other below.
Egypt receivables and other, net – As of the Merged Concession Effective Date, an effective date adjustment was owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date (as defined herein) (the “Effective Date Adjustment”). The Company recognized a receivable of $ 67.5 million for the Effective Date Adjustment as of October 2022, based on historical realized prices (the “Backdated Receivable”). The Backdated Receivable was fully settled as of March 31, 2025.
For credit losses associated with Egypt receivables and other, net, see allowance for credit losses and other below.
Value added tax and other receivables, net – The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”).
As of December 31, 2025 and 2024 , the outstanding VAT receivable balance was approximately $ 1.1 million and $ 2.8 million, net to VAALCO, respectively. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other expense, net” line item of the consolidated statements of operations and comprehensive income. For the allowance associated with VAT, see allowance for credit losses and other below.
Allowance for credit losses and other – On January 1, 2023 , the Company adopted Accounting Standards Update 2016 - 13, Financial Instruments—Credit Losses (“ ASU 2016 - 13 ”). ASU 2016 - 13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates. All other amounts previously disclosed as allowances for bad debt were transferred to allowances for credit loss and other.
The Company estimates the current expected credit loss and other allowances based primarily using either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance 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;
F-11
• Accounts with joint venture owners, net;
• Egypt receivables and other, net; and
• Loans to employees.
During the years ended December 31, 2025 and 2024, the Company recognized $ 0.1 million and $ 7.7 million in credit loss and other allowances, respectively, mainly due to VAT receivables and receivables from joint venture partners.
The following table provides an analysis of the change in the aggregate credit loss and other allowances:
Year Ended December 31,
2025 2024
(in thousands)
Allowance for credit losses and other
Balance at beginning of period $ ( 2,554 ) $ ( 6,029 )
Credit losses and other ( 1,126 ) ( 6,304 )
Credit recoveries and other 1,028 ( 1,421 )
Reversal of allowance resulting from the settlement of the related receivable — 11,200
Balance at end of period $ ( 2,652 ) $ ( 2,554 )
Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon and Cote d’Ivoire, inventories represent the Company's share of crude oil produced and stored on the FSO and the FPSO but unsold at the end of each period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold.
Prepayments and other – Included in “Prepayments and other” line item of the Company’s December 31, 2025 and 2024 consolidated balance sheet are the following assets:
2025 2024
(in thousands)
Egypt advances to contractors $ 5,485 $ 3,665
Prepaid fixed asset progress payments 3,747 9
Deposits 3,292 2,933
Derivatives 3,053 119
Employee loans and advances 2,398 1,430
Prepaid royalties 285 3,089
Other prepayments 6,110 3,728
Total prepayments and other $ 24,370 $ 14,973
Crude oil, natural gas and NGLs properties and equipment, net – The Company uses the successful efforts method of accounting for crude oil, natural gas and NGLs producing activities.
• Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to
F-12
evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Interest expense is capitalized for qualifying assets under construction. Capitalized interest costs are included in Crude oil, natural gas and NGLs properties and equipment, net.
• Capitalized equipment, spare parts and other – Capitalized equipment, spare parts and other represents the costs incurred in purchasing and bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle.
• Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block basis under the unit-of-production method based upon estimates of total proved developed reserves. Depletion of leasehold acquisition costs are provided on a block basis under the unit-of-production method based upon estimates of total proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, natural gas and NGLs producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically five years for office and miscellaneous equipment and five to seven years for leasehold improvements.
• Unproved Property Cost – Significant unproved properties are assessed individually for impairment and when events or circumstances indicate that the carrying value of property may not be recovered, the capitalized costs of the related properties would be expensed. The unproved property costs are not subject to depreciation, depletion and amortization, until they are classified as proved properties.
• Impairment – The Company reviews the crude oil, natural gas and NGLs properties and equipment, net for impairment on a block basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or periods of sustained declines in commodity prices. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value.
Capitalized equipment inventory is reviewed regularly for obsolescence. During the year ended December 31, 2025, we recorded an inventory write-down of $ 2.4 million for estimated obsolete inventory as well as inventory whose carrying value is in excess of net realizable value and the related expense is included in the “Other operating income (expense), net” line item in the Consolidated Statements of Operations and Comprehensive Income (Loss).
When undeveloped crude oil, natural gas and NGLs leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to unproved property costs in the Etame Marin block in Gabon, Canada, Egypt and in Block P in Equatorial Guinea.
• Assets and Liabilities Held for Sale – The Company classifies disposal groups as held for sale in the period in which all of the following criteria are met: (1) management, having the authority to approve the action, commits to a plan to sell the disposal group; (2) the disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such disposal groups; (3) an active program to locate a buyer or buyers and other actions required to complete the plan to sell the disposal group have been initiated; (4) the sale of the disposal group is probable, and transfer of the disposal group is expected to qualify for recognition as a completed sale, within one year, except if events or circumstances beyond the Company’s control extend the period of time
F-13
required to sell the disposal group beyond one year; (5) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value; and (6) actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.
A disposal group that is classified as held for sale is initially measured at the lower of its carrying amount or fair value less any costs to sell. Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Subsequent changes in the fair value of a disposal group less any costs to sell are reported as an adjustment to the carrying amount of the disposal group, as long as the new carrying amount does not exceed the carrying amount of the asset at the time it was initially classified as held for sale. Depreciation, depletion and amortization expense is not recorded on assets to be divested once they are classified as held for sale. In the initial period in which the disposal group meets the criteria to be classified as held for sale, the assets and liabilities of the disposal group are separately presented as assets held for sale and liabilities held for sale, respectively, in the Consolidated Balance Sheets.
When items of crude oil, natural gas and NGLs properties and equipment are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of crude oil, natural gas and NGLs properties and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale.
Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842 , Leases. If a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments.
Asset retirement obligations ( “ ARO ” ) – The Company has legal obligations to remove tangible equipment and restore land or seabed at the end of crude oil, natural gas and NGLs production operations. The removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of onshore or offshore crude oil, natural gas and NGLs platforms, and capping pipelines. Estimating the future restoration and removal costs requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with crude oil, natural gas and NGLs properties and equipment, net. The Company uses current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil, natural gas and NGLs properties and equipment, net. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related capitalized asset retirement cost or through a charged to earnings, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a units-of-production basis for crude oil, natural gas and NGLs properties and equipment, net production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain.
Revenue recognition – The Company’s revenues are derived from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers.
Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. The Company mainly satisfies its performance obligations at a point in time. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy
F-14
regarding classification of these type of expenses. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
Revenues associated with the sales of the Company’s crude oil, natural gas, condensates and natural gas liquids (“NGLs”) are recognized by reference to actual volumes sold and quoted market prices in active markets for crude oil, natural gas, condensates and NGLs, adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable.
Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs.
Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.
Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.
For restricted stock awards, the grant date fair value is determined using the market value of the common stock on the date of grant.
The stock-based compensation expense for equity awards is recognized over the period that services are provided. For awards considered liabilities under US GAAP, awards are measured at fair value on the grant date and remeasured at fair value until the award is settled.
Legal Contingencies – We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue losses associated with legal claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred.
Foreign currency transactions – The U.S. dollar is the functional currency of the Company’s foreign operating subsidiaries except for Canada which has a functional currency of the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income (loss). The Company recognized losses on foreign currency transactions of $ 0.7 million in 2025 , $ 1.8 million in 2024 and $ 0.9 million in 2023 .
Income taxes – The tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting
F-15
additional tax liabilities. While the income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil, which is due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, will not be realized. A valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered are earnings generated in previous periods, forecasted earnings and the expiration period of carryovers.
Derivative instruments and hedging activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.
The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations and comprehensive income (loss).
Fair value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1 – Inputs are observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date.
Level 2 – Inputs are observable market-based inputs or unobservable inputs that are corroborated by market data.
Level 3 – Inputs are unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, natural gas and NGLs properties and equipment, net, asset retirement assets and liabilities and assets acquired and liabilities assumed in a business combination, and assets and liabilities held for sale. The Company uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When the Company is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows. The expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors, most of which are often outside of management's control. However, assumptions used to reflect a market participant's view of long term prices, costs and other factors and are consistent with assumptions used in the Company's business plans and investment decisions.
F-16
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, 2025
Balance Sheet Line Level 1 Level 2 Level 3 Total
(in thousands)
Assets
Derivative asset Prepayments and other $ — $ 3,053 $ — $ 3,053
$ — $ 3,053 $ — $ 3,053
Liabilities
Derivative liability Accrued liabilities and other $ — $ 207 $ — $ 207
$ — $ 207 $ — $ 207
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, noncurrent Other long term assets $ — $ 1,209 $ — $ 1,209
$ — $ 1,328 $ — $ 1,328
Liabilities
Derivative liability Accrued liabilities and other $ — $ 17 $ — $ 17
$ — $ 17 $ — $ 17
See Note 9. Derivatives for further details of the Company’s derivative contracts.
Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.
3 . NEW ACCOUNTING STANDARDS
Adopted
In December 2023 , the Financial Accounting Standards Board (“FASB”) issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in this update improve the transparency of income tax disclosures by requiring (1) consistent categories and greater disaggregation of information in the rate reconciliation and (2) income taxes paid disaggregated by jurisdiction. This update improves the effectiveness and comparability of disclosures by requiring disaggregation by jurisdiction of disclosures of pretax income (or loss) and income tax expense (or benefit). This ASU is to be applied on a prospective basis, with retrospective application permitted. The guidance in this update is effective for fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-09 for the year
F-17
ended December 31, 2025 on a prospective basis. The adoption of ASU 2023-09 required additional income tax disclosures and did not have an impact on the Company’s consolidated financial position or results of operations.
Not Yet Adopted
In November 2024, the FASB issued ASU 2024-03, Accounting Standards Update 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve financial reporting by requiring that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU to our notes to the consolidated financial statements and processes.
In July 2025, the FASB issued ASU 2025-05, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets. The ASU introduces a practical expedient and, for non-public business entities, an accounting policy election to simplify the application of credit loss guidance to short-term receivables and contract assets by allowing consideration of post-balance-sheet collections. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The Company has elected to not adopt the practical expedient. The Company, when estimating its credit losses, will continue to consider available information that is relevant to its assessment of the collectibility of cash flows, including historical losses, current economic conditions, and reasonable and supportable forecasts. Management will continue to monitor changes in the Company’s portfolio, economic conditions, and future guidance issued by the Financial Accounting Standards Board to determine whether election of the practical expedient would be appropriate in future reporting periods.
4 . ACQUISITIONS AND DIVESTITURE
Canada Asset Divestment
In December 2025, the Company’s Board of Directors approved the sale of the Company’s oil and gas properties in Canada. As of December 31, 2025, the assets and liabilities associated with the Canada Asset Divestment (defined below) were classified as held for sale on our Consolidated Balance Sheet. The Canada Asset Divestment does not qualify as a discontinued operation under FASB ASC Topic 205, Presentation of Financial Statements , as it does not represent a strategic shift that will have a major effect on the Company's operations or financial results.
Upon classification as held for sale, the Company recorded an impairment loss of $ 67.2 million to adjust the carrying value of the assets held for sale to their estimated fair value less cost to sell. The impairment loss is presented in the “Impairment loss on assets held for sale” line item in the Consolidated Statements of Operations and Comprehensive Income (Loss). The following table sets forth the carrying value of the assets and liabilities held for sale:
Balance Sheet Classification December 31, 2025
(in thousands)
Current assets (Derivative assets, current) Current assets held for sale $ 179
Crude oil, natural gas and NGLs properties and equipment, net
Noncurrent assets held for sale 31,826
Current liabilities (Asset retirement obligation, current) Current liabilities held for sale ( 183 )
Asset retirement obligations Noncurrent liabilities held for sale ( 7,403 )
Net assets held for sale $ 24,419
As previously discussed, the Company reviews the crude oil, natural gas and NGLs properties and equipment quarterly at each reporting period or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. Impairment assessments are performed in connection with the preparation of the financial statements, ensuring that recognized losses reflect conditions as of the reporting date. As further discussed above, the Company determined that the Canada Asset Divestment met the criteria for classification as held for sale as of December 31, 2025. This determination constituted a triggering event requiring an impairment assessment, which was performed concurrently with the Company’s periodic impairment evaluation as of December 31, 2025.
On February 4, 2026, the Company entered into an asset purchase agreement (the “Canada APA”) to sell all of our operating assets in Canada (the “Canada Asset Divestment”) to a third party purchaser for a purchase price of $ 24.4 million
F-18
(C$ 33.4 million) to be settled in cash, subject to customary adjustments. The Canada Asset Divestment closed on February 19, 2026 with an effective date of February 1, 2026 for an adjusted purchase price of $ 25.5 million (C$ 34.9 million), subject to additional customary post-closing adjustments. The net cash proceeds from the divestment was primarily used to fund our capital expenditures and for working capital purposes. The Canada Asset Divestment represents the Company’s complete exit of its Canadian oil and gas operations.
Acquisition of Interest in CI-705 Block
In March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire. The Company is the operator of the CI-705 block with a 70 % working interest and a 100 % paying interest through a commercial carry arrangement and is partnering with two other parties. The CI-705 block is located in the Tano basin, west of the Company's CI-40 Block, where the Baobab and Kossipo oil fields are located. The total amount of acquisition costs for this transaction is approximately $ 3.0 million.
FPSO Acquisition
In February 2025, the Company, through the joint operating agreement operator, completed the acquisition of the Baobab floating, production, storage and offloading vessel (the “Baobab FPSO”) in Côte d'Ivoire for a total purchase price of $ 20.0 million, or approximately $ 6.1 million net cost to the Company.
Svenska Acquisition
On April 30, 2024, the Company completed the acquisition of all of the issued shares in the capital of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (“Svenska”) for a net adjusted purchase price of $ 40.2 million (the “Svenska Acquisition”). The total purchase price consideration was funded with $ 40.2 million of the Company’s cash-on-hand. Cash acquired in the business combination included $ 31.8 million of cash and cash equivalents as well as restricted cash of $ 8.8 million which nets to $ 0.4 million cash received on the business combination within the purchase price allocation.
As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, an initial $ 19.9 million bargain purchase gain was recognized as of the close date. The purchase price allocation was finalized in the fourth quarter of 2024 and the Company made adjustments to the amounts assigned to the net assets acquired based on new information obtained about facts and circumstances that existed as of the Svenska Acquisition date. As a result, the bargain purchase gain was reduced by $ 6.4 million. The bargain purchase gain is primarily attributable to a stronger forward pricing curve for oil and gas reserves on the date of the closing of the acquisition than was used for the purposes of the negotiations of the purchase price paid for Svenska.
The Svenska Acquisition qualified as a business combination and was accounted for using the acquisition method of accounting. The following tables summarize the cash paid for the purchase price and the final purchase price allocation of the acquisition consideration.
F-19
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
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 year ended December 31, 2024 and 2023 , as if the acquisition had been consummated on January 1, 2023. The unaudited pro forma results do not purport to represent what the Company’s
F-20
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 (a)(b)
$ 38,336 95,740
Basic net income per share:
Net income $ 38,336 $ 95,740
Net income per share $ 0.37 $ 0.90
Basic weighted average shares outstanding 103,669 106,376
Diluted net income per share:
Net income $ 38,336 $ 95,740
Net income per share $ 0.37 $ 0.90
Diluted weighted average shares outstanding 103,747 106,555
(a) The unaudited pro forma net income (loss) for the year ended December 31, 2024 excludes a nonrecurring pro forma adjustment directly attributable to the Svenska Acquisition, consisting of a bargain purchase gain of $ 13.5 million.
(b) The unaudited pro forma net income (loss) for the year ended December 31, 2023 excludes a nonrecurring pro forma adjustment attributable to the TransGlobe Acquisition, consisting of a bargain purchase gain adjustment of $ 1.4 million.
5 . EARNINGS PER SHARE
Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.
F-21
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,
2025 2024 2023
(in thousands)
Net income (loss) (numerator):
Net income (loss) $ ( 41,391 ) $ 58,490 $ 60,354
Income attributable to unvested shares ( 475 ) ( 714 ) ( 632 )
Numerator for basic ( 41,866 ) 57,776 59,722
Income attributable to unvested shares — — 1
Numerator for dilutive $ ( 41,866 ) $ 57,776 $ 59,723
Weighted average shares (denominator):
Basic weighted average shares outstanding 104,055 103,669 106,376
Effect of dilutive securities — 78 179
Diluted weighted average shares outstanding 104,055 103,747 106,555
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be antidilutive 3,608 516 385
6 . 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.
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
F-22
delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete.
The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. Historically as operator, the volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the volumes sold exceeded the Company’s ownership interest.
For each lifting completed under a COSPA or COSMA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
The terms of the Etame PSC includes provisions for payments to the government of Gabon for: royalties based on 13 % of production at the published price and a shared portion of Profit Oil determined based on daily production rates, as well as a gross carried working interest of 7.5 % (increasing to 10 % beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments.
To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment. Payments for royalties are reflected as a reduction in revenues from customers.
With respect to the government’s share of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the consolidated statements of operations and comprehensive income (loss), the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. The amount associated with the Profit Oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported in current income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, which is the period in which it lifts the crude oil. For the years ended December 31, 2025 and 2024, we made total in-kind payments through production liftings of $ 31.8 million and $ 30.3 million, respectively. As of December 31, 2025 and 2024, we had foreign income tax payables of $ 18.8 million and $ 40.0 million, respectively.
Certain amounts associated with the carried interest in the Etame Marin block are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs that would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues.
The following table presents revenues in Gabon from contracts with customers as well as revenues associated with the obligations under the Etame PSC:
Year Ended
December 31,
2025 2024 2023
Revenues from customer contracts: (in thousands)
Sales under the COSPA or COSMA $ 176,508 $ 205,965 $ 261,801
Gabonese government share of Profit Oil taken in-kind 31,845 30,256 32,776
Carried interest recoupment 1,865 2,276 5,301
Royalties ( 28,480 ) ( 32,543 ) ( 39,532 )
Net revenues $ 181,738 $ 205,954 $ 260,346
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.
F-23
Customer sales generally occur when sales are directly to EGPC or haphazardly production is sold through a cargo lifting. The Company records EGPC’s share of production as royalties which are netted against revenue, whether EGPC’s share of production arises from EGPC’s share of Profit Oil or excess Cost Oil.
With respect to Egyptian income taxes, these taxes are paid by EGPC on behalf of the Company out of EGPC’s share of production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of the Company are recognized as crude oil revenue and income tax expense.
EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC’s cooperation and approval to schedule liftings. Once liftings occur, the Company has a 30-day collection cycle on liftings as a result of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings.
In some instances, the Company will borrow or loan production volumes in order to achieve a required amount of crude oil for cargo sales. In these instances, the Company can be in an overlift or underlift position. Regardless of being in an overlift or underlift position, sales are based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds and the Company will record a payable, if in an overlift position, or a receivable, if in an underlift position, based on the fair value of the consideration received or receivable.
The following table presents revenues in Egypt from contracts with customers:
Year Ended December 31,
2025 2024 2023
Revenues from customer contracts: (in thousands)
Gross sales $ 225,957 $ 250,946 $ 272,613
Royalties ( 85,250 ) ( 104,449 ) ( 110,569 )
Selling costs ( 744 ) ( 531 ) ( 995 )
Net revenues $ 139,963 $ 145,966 $ 161,049
Canada
Prior to the Canada Asset Divestment, customer sales generally occurred on a daily basis when crude oil, natural gas, condensate or NGL’s were sold, normally via pipeline, to a delivery point. There is a single performance obligation (delivering crude oil, natural gas, condensate or NGL’s to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. The Company paid royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime. The Company recorded revenues net of royalties.
Settlement of accounts receivable in Canada occurred on the 25th of the following month following production.
The following table presents revenues in Canada from contracts with customers:
Year Ended December 31,
2025 2024 2023
Revenues from customer contracts: (in thousands)
Oil revenue $ 15,319 $ 28,418 $ 28,287
Gas revenue 2,052 1,849 3,467
NGL revenue 5,804 7,646 8,440
Other revenue 164 213 —
Royalties ( 3,330 ) ( 5,009 ) ( 5,821 )
Selling costs ( 835 ) ( 1,131 ) ( 702 )
Net revenues $ 19,174 $ 31,986 $ 33,671
F-24
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 fr om the Baobab field is shared under a PSC (the “Cote d'Ivoire PSC”). In addition, in March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire as the operator with a 70 % working interest and a 100 % paying interest.
Revenues from contracts with customers are generated from sales in Cote d'Ivoire pursuant to crude oil sales and purchase agreements (“COSPAs”), and revenues are recognized when a lifting, as defined below, is completed.
Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete.
The Company accounts for sales based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds. The volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the volumes sold exceeded the Company’s ownership interest.
For each lifting completed under the sales and purchase agreement, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
Cost Oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the government state oil company. Profit Oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the government of Cote d'Ivoire (the “Ivorian Government”). The Ivorian Governments’ share of Profit Oil attributable to the Company’s equity interest is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. In addition, under the terms of the Cote d'Ivoire PSC, the tax payments to the Ivorian Government are deemed satisfied by its share of the Profit Oil.
The following table presents revenues in Cote d'Ivoire from contracts with customers:
Year Ended December 31,
2025 2024
Revenues from customer contracts: (in thousands)
Sales under the sales and purchase agreements $ 16,528 $ 87,870
Cote d’Ivoire government share of Profit Oil taken in-kind 1,869 7,212
Net revenues $ 18,397 $ 95,082
Information about the Company ’ s most significant customers -
For the years ended December 31, 2025, 2024 and 2023, our revenue concentration by customer for each operating segment are shown on the table below.
Year Ended December 31,
2025 2024 (1)
2023
Gabon 100 % 100 % 100 %
Egypt 100 % 100 % 62 % and 38 %
Cote d'Ivoire 100 % 87 % and 13 %
— %
Canada 51 %, 20 % and 15 %
41 %, 32 % and 21 %
52 %, 37 % and 7 %
(1) For Cote d'Ivoire, reflects sales from April 30, 2024 through December 31, 2024 related to the Svenska Acquisition.
F-25
7. INCOME TAXES
Income (loss) before income taxes is attributable as follows:
Year Ended December 31,
(in thousands) 2025 2024 2023
U.S. $ ( 24,853 ) $ ( 26,337 ) $ ( 15,781 )
Foreign ( 1,716 ) 166,134 165,927
$ ( 26,569 ) $ 139,797 $ 150,146
Provision for income taxes related to income (loss) consists of the following:
Year Ended December 31,
2025 2024 2023
U.S. Federal: (in thousands)
Current $ — $ — $ —
Deferred ( 1,940 ) ( 1,698 ) 6,214
Foreign:
Current 44,341 98,882 92,642
Deferred ( 27,579 ) ( 15,877 ) ( 9,079 )
Total $ 14,822 $ 81,307 $ 89,777
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) 2025
U.S. Federal Statutory Tax Rate $ ( 5,580 ) 21.00 %
Domestic Federal
Tax Credits - Foreign Tax Credit ( 13,982 ) 52.63 %
Changes in Valuation Allowance 7,385 ( 27.79 ) %
Cross-border tax laws - US taxation of foreign disregarded entity 8,242 ( 31.02 ) %
Nontaxable or nondeductible items 806 ( 3.03 ) %
Foreign Tax Effects
Gabon
Statutory income tax rate differential 4,923 ( 18.53 ) %
Rate difference between Gabon statutory tax rate and the PSC 9,435 ( 35.51 ) %
Nontaxable or nondeductible items:
Non Recoverable Costs 1,067 ( 4.02 ) %
Nondeductible Interest 1,670 ( 6.29 ) %
Impact of revenue differences between production and lifting ( 8,075 ) 30.39 %
Carried interests ( 1,020 ) 3.84 %
Other reconciling items 478 ( 1.80 ) %
Changes in Valuation Allowance 2,095 ( 7.89 ) %
Egypt
Statutory income tax rate differential 9,067 ( 34.13 ) %
Nontaxable or nondeductible items:
Non Recoverable Costs 2,288 ( 8.61 ) %
Other reconciling items ( 92 ) 0.35 %
Changes in Valuation Allowance 356 ( 1.34 ) %
F-26
Canada
Statutory income tax rate differential 4,184 ( 15.75 ) %
Subnational income taxes ( 5,580 ) 21.00 %
Changes in Valuation Allowance 16,045 ( 60.39 ) %
Cote D'Ivoire
Statutory income tax rate differential ( 716 ) 2.70 %
Rate difference between statutory tax rate and the PSC ( 12,197 ) 45.91 %
Nontaxable or nondeductible items:
Non Recoverable Costs 1,033 ( 3.89 ) %
Stat to US GAAP adjustments ( 1,250 ) 4.71 %
Cost Recovery Uplift ( 9,167 ) 34.50 %
Changes in Valuation Allowance 1,834 ( 6.90 ) %
Equatorial Guinea
Statutory income tax rate differential ( 119 ) 0.45 %
Changes in Valuation Allowance 744 ( 2.80 ) %
Sweden
Tax Credits - Foreign Tax Credit ( 3,767 ) 14.18 %
Cross-border tax laws - Sweden taxation of foreign disregarded entity ( 2,885 ) 10.86 %
Nontaxable or nondeductible items:
Realized foreign exchange gain 4,036 ( 15.19 ) %
Other reconciling items ( 100 ) 0.38 %
Changes in Valuation Allowance 3,126 ( 11.76 ) %
Other
Nontaxable or nondeductible items:
Other reconciling items 538 ( 2.03 ) %
Total $ 14,822 ( 55.77 ) %
Income taxes paid (net of refunds received) were as follows:
December 31,
(in thousands)
2025
2024
Gabon
$ 36,739 $ 31,109
Egypt
29,025 31,355
Cote d’Ivoire
2,221 9,155
Total taxes paid
$ 67,985 $ 71,619
Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered.
In assessing the realizability of the deferred tax assets, the Company considers all available positive and negative evidence by jurisdiction to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, future operating conditions, particularly as related to prevailing crude oil prices.
On the basis of this evaluation, as of December 31, 2025, a valuation allowance of $ 203.6 million has been recorded to recognize only the portion of the deferred tax asset that is more likely than not to be realized. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased.
F-27
The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows:
December 31,
(in thousands) 2025 2024
Deferred tax assets:
Fixed assets (1)
$ 40,988 $ 35,541
Foreign tax credit carryforward 133,803 123,660
Net operating losses 58,892 56,317
Asset retirement obligations 48,015 20,384
ROU lease liabilities 8,567 9,973
Accrued liabilities 16,071 19,686
Receivables ( 146 ) ( 1,788 )
Other 3,846 2,682
Total deferred tax assets 310,036 266,455
Valuation allowance ( 203,624 ) ( 173,140 )
Net deferred tax assets $ 106,412 $ 93,315
Deferred tax liabilities:
Basis difference in fixed assets ( 115,217 ) ( 131,639 )
Net deferred tax liabilities $ ( 115,217 ) $ ( 131,639 )
(1) This line includes ROU lease asset.
The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2025, it is not practicable to estimate the unrecognized deferred tax liability. However, unrecognized deferred taxes on remittance of these funds are not expected to be material.
The Company has NOL’s, in the following jurisdictions as of December 31, 2025:
Jurisdiction Amount
(in thousands)
Expiration Period
Egypt $ 14,596 2026-2028
Canada $ 91,662 2031-2040
Equatorial Guinea $ 127,564 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, 2025 and 2024. The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense.
The Company is subject to income taxation in the United States and various foreign jurisdictions, including Canada. The Company’s Canadian subsidiaries are currently under examination by the Canada Revenue Agency (“CRA”) with respect to the tax treatment of the disposition of shares of certain foreign affiliates for taxation years included in the year ended December 31, 2022.
In January 2026, the Company received an assessment from the CRA related to this examination. The Company is currently evaluating the assessment and available administrative remedies, including the filing of a notice of objection. The Company is also considering this matter in connection with the previously announced sale of the Company’s Canadian assets. As of December 31, 2025, there have been no developments or new information that would require the Company to record an unrecognized tax benefit. Based on currently available information, the Company does not believe that the
F-28
ultimate resolution of this matter will have a material adverse effect on its consolidated financial position, tax expense, results of operations, or cash flows; however, the final outcome remains uncertain.
For the years ended December 31, 2025 , 2024 and 2023, the Company is subject to foreign and U.S. federal taxes only, with no allocations made to state and local taxes. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions.
Jurisdiction Years
U.S. 2015 - 2025
Gabon 2021 - 2025
Egypt 2020 - 2025
Canada 2020 - 2025
Sweden 2019 - 2025
Cote d'Ivoire 2022 - 2025
8. CRUDE OIL, NATURAL GAS AND NGLs PROPERTIES AND EQUIPMENT, NET
The Company’s crude oil, natural gas and NGLs properties and equipment, net, at December 31, 2025 and 2024 is comprised of the following:
2025 2024
(in thousands)
Crude oil, natural gas and NGLs properties and equipment, net
Wells, platforms and other production facilities $ 1,016,019 $ 1,593,243
Work-in-progress 214,213 44,517
Unproved properties 52,079 60,761
Capitalized equipment, spare parts and other 84,471 75,581
1,366,782 1,774,102
Accumulated depreciation, depletion, amortization and impairment ( 780,687 ) ( 1,235,999 )
Crude oil, natural gas and NGLs properties and equipment, net $ 586,095 $ 538,103
Unproved property costs
See the table below for the list of unproved property costs at December 31, 2025 and 2024:
2025 2024
(in thousands)
Unproved Property Costs
Gabon 15,235 $ 13,735
Equatorial Guinea 10,000 10,000
Egypt 11,035 11,542
Cote d'Ivoire 15,809 12,775
Canada — 12,709
Unproved Property Costs $ 52,079 $ 60,761
At December 31, 2025, the Company classified $ 31.8 million of net Crude oil, natural gas and NGLs properties and equipment, including unproved property costs of $ 13.1 million, as “Noncurrent asset held for sale” on the Consolidated Balance Sheet.
F-29
Exploration expense
During the year ended December 31, 2025, we incurred exploration expenses of $ 8.9 million, which included exploratory costs related to a well determined to be not commercially viable in South Ghazalat, the cost of additional seismic data to be used in Block 705 in Cote d’Ivoire, and expenses related to Blocks G and H in Gabon. We had minimal exploration expenses during 2024.
9. DERIVATIVES
We have entered into derivative contracts primarily with counterparties that are also lenders under the 2025 RBL Facility (defined below) to hedge price risk associated with a portion of our oil, natural gas and NGLs production. In addition, pursuant to the terms of the 2025 RBL Facility agreement, if the aggregate borrowings under the 2025 RBL Facility exceeds 35 % of the lower of (a) the available total commitments and (b) the applicable borrowing base amount, we are required to enter into commodity price hedge positions covering certain volumes of anticipated future production set out in the banking case. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points. See table below for the list of outstanding contracts as of December 31, 2025:
Settlement Period
Instrument Index January 2026 - March 2026 April 2026 - June 2026 July 2026 - September 2026 October 2026 - December 2026
Crude oil:
Collars Dated Brent
Total volumes (Bbls) 400,000 360,000 75,000 —
Weighted average floor price ($/Bbl) $ 62.29 $ 61.88 $ 65.00 $ —
Weighted average ceiling price ($/Bbl) $ 68.63 $ 67.95 $ 71.00 $ —
Natural Gas (a) :
Swaps AECO 7A
Total volumes (GJs) (b)
225,000 150,000 150,000 50,000
Weighted average fixed price (CAD/GJ) $ 2.99 $ 2.80 $ 2.80 $ 2.80
(a) Natural gas hedge contracts were assumed by the third-party purchaser upon closing of the sale pursuant to the Canada APA.
(b) One gigajoule (GJ) equals one billion joules (J). A gigajoule of natural gas is approximately 25.5 cubic meters standard conditions.
See Note 2. Summary of Significant Accounting Policies for further details on the measurement of our derivative assets at fair value.
The following table sets forth the gain (loss) on derivative instruments on the Company’s consolidated statements of operations and comprehensive income (loss):
Year Ended December 31,
Derivative Item Statements of Operations Line 2025 2024 2023
(in thousands)
Commodity derivatives Cash settlements paid on matured derivative contracts, net $ ( 48 ) $ ( 453 ) $ ( 127 )
Unrealized gain (loss) 2,924 ( 292 ) 359
Derivative instruments gain (loss), net $ 2,876 $ ( 745 ) $ 232
F-30
10. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in the Company’s asset retirement obligations:
Year Ended December 31,
(in thousands) 2025 2024
Beginning balance $ 79,766 $ 47,343
Accretion 6,364 4,753
Additions 2 27,424
Revisions 427 981
Settlements ( 225 ) ( 368 )
Liabilities classified as held for sale ( 7,586 ) —
Foreign currency loss ( 342 ) ( 367 )
Ending balance 78,406 79,766
Less: current obligations — ( 1,174 )
Long-term asset retirement obligation $ 78,406 $ 78,592
Accretion is recorded in the line item “Depreciation, depletion and amortization” on the consolidated statements of operations and comprehensive income (loss).
11 . COMMITMENTS AND CONTINGENCIES
Abandonment funding
Gabon
Under the terms of the Etame PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the life of the Etame Marin Block, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In August 2023 , an abandonment study was completed which estimated abandonment costs of approximately $ 77.9 million ($ 45.9 million, net to VAALCO) on an undiscounted basis. The abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the PSC. At December 31, 2025, $ 10.7 million ($ 6.3 million, net to VAALCO) on an undiscounted basis has been funded. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.
In the first quarter of 2023 , the Directorate of Hydrocarbons in Gabon approved a $ 26.6 million ($ 15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $ 15.6 million in March 2023 . No other activity occurred in the abandonment funding account through the end of 2025. The Company is working with the Directorate of Hydrocarbons in Gabon to establish a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.
Share Buyback Program
On November 1, 2022, the Company announced that the Company’s Board of Directors formally ratified and approved a share buyback program. The Board of Directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934. The 10b5-1 Plan provided for an aggregate purchase of currently outstanding common stock up to $ 30 million over a maximum period of 20 months. Payment for shares repurchased under the share buyback program were funded using the Company's cash on hand and cash flow from
F-31
operations. The share buyback program was completed on March 12, 2024. Under the share buyback program, we purchased a total of 6,797,711 shares at an average price of $ 4.41 per share.
Regulatory and Joint Interest Audits and Related Matters
The Company is subject to periodic audits by various government agencies from the international jurisdictions where we operate, including audits by the respective governments and other members of the Company's joint operating agreements.
Merged Concession Agreement
The Company is a party to the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”). In accordance with the Merged Concession Agreement, we were required to make $ 10.0 million annual modernization payments through February 1, 2026 . As of December 31, 2025, all modernization payments had been fully settled either through actual cash payments or through the issuance of credit against receivables owed from EGPC.
The Company also has minimum financial work commitments of $ 50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 for a total of $ 150 million over the 15 year license contract term. Through December 31, 2025 , the Company's financial work commitments have exceeded 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, 2025 are $ 10.0 million in 2026 , $ 10.0 million in 2027 , $ 10.0 million in 2028 , $ 10.0 million in 2029, $ 10.0 million in 2030 and $ 50.0 million in 2031 and thereafter.
Domestic Market Obligation
Under the terms of the respective PSCs in Gabon and Cote d'Ivoire, the Company can be required to sell to the Government or another entity designated by the Government, a certain percentage of its Profit Oil to meet the needs of the domestic market.
Drilling Rig Commitment
The Company entered into a bareboat charter agreement (the “Bareboat Charter”) during the fourth quarter of 2024 to charter a drilling rig for its drilling program in Gabon. Pursuant to the Bareboat Charter, the Company also entered into a service agreement with a third party for purposes of maintaining and operating the drilling rig on its behalf. The Bareboat Charter commenced on November 2025 upon the mobilization of the drilling rig towards the Company’s first well and has a noncancellable period of 300 days plus five single well options. The Bareboat Charter stipulates fixed day rates and other variable payments.
12. DEBT
In April 2025, the Company drew down $ 60.0 million under the 2025 RBL Facility. The borrowing accrues interest at a rate of 10.8 % per annum which is based on the Term SOFR plus the Applicable Margin of 6.5 % per annum. In addition, the borrowing is due to be repaid within three months from the drawdown date with, subject to certain conditions, the option to rollover the debt upon maturity.
As of December 31, 2025, there were $ 60.0 million of outstanding borrowings under the 2025 RBL Facility. There were no outstanding borrowings as of December 31, 2024.
In addition, as of December 31, 2025 and 2024, we were in compliance with all of our debt covenants.
2025 RBL Facility
On March 4, 2025, the Company and certain of its subsidiaries (the “Vaalco Energy Group”), entered into a reserves-based facility agreement (the “2025 Facility Agreement”) providing for a senior secured reserve-based revolving credit facility (the “2025 RBL Facility”) with The Standard Bank of South Africa Limited (acting through its Corporate and Investment Banking Division) as agent and security agent, The Standard Bank of South Africa Limited, Isle of Man Branch and the other financial institutions named in the 2025 Facility Agreement (the “Lenders”), providing for the 2025 RBL Facility.
F-32
The 2025 RBL Facility had initial aggregate commitments of $ 190.0 million (the “Initial Total Commitments”) as of March 4, 2025, with an initial borrowing base of $ 182.0 million, which was further increased to $ 184.0 million in April 2025 in accordance with the conditions that were met subsequent to entering into the 2025 Facility Agreement. The Initial Total Commitments originally would reduce semi-annually by $ 19.0 million starting from September 30, 2026. The borrowing base amount is calculated pursuant to the 2025 RBL Facility Agreement and redetermined on March 31 and September 30 of each year beginning June 30, 2025 and in certain circumstances, other interim triggers set out in the 2025 Facility Agreement. In 2025, we completed our June 30 and September 30 borrowing base redeterminations, which increased the borrowing base to $ 190.0 million.
The Company may, at any time prior to the date falling 30 months from the date of the 2025 Facility Agreement and subject to the conditions and process set out in the 2025 RBL Facility Agreement, give notice to the agent to increase the Initial Total Commitment up to a maximum amount of $ 300.0 million. Effective October 17, 2025, the Lenders approved to (i) extend the first date on which the Initial Total Commitments will be reduced from September 30, 2026 to March 31, 2027, and (ii) update the semi-annual commitment reduction amounts from $ 19.0 million to $ 10.0 million on March 31, 2027, and $ 22.5 million starting on September 30, 2027.
As of December 31, 2025, we had $ 190.0 million of aggregate facility commitments and $ 130.0 million of available borrowing capacity under the 2025 RBL Facility.
In addition, subject to certain conditions precedent, certain existing Lenders under the 2025 RBL Facility agreed to increase their initial commitment effective January 23, 2026 from $ 190.0 million to $ 255.0 million. The increase in commitments was undertaken with the existing accordion feature included in the 2025 RBL Facility.
On February 4, 2026, the Company borrowed an additional $ 65.0 million under the 2025 RBL Facility. The borrowing accrues interest at a rate of 10.2 % per annum which is based on the Term SOFR plus the Applicable Margin of 6.5 % per annum. In addition, the borrowing is due to be repaid within one month from the drawdown date with, subject to certain conditions, the option to rollover the debt upon maturity.
Each loan under the 2025 RBL Facility will bear interest at a rate equal to Term Secured Overnight Financing Rate (“SOFR”) plus the Applicable Margin of (i) 6.50 %, from the date of the 2025 Facility Agreement until the date on which the renovation and repair of the floating production storage and offloading tanker facility named Baobab Ivorian MV10 FPSO for use in connection with the development of the Baobab field (the “Baobab FPSO Renovation”) meets certain completion tests defined in the 2025 RBL Facility Agreement and (ii) thereafter, 6.00 % until the Final Maturity Date (defined below). We shall pay the accrued interest on the last day of each applicable interest period, which interest period may be, at our option, one, three or six months or such other period as agreed to between us and the Lenders.
The 2025 RBL Facility will mature on the earlier of (i) March 4, 2031, which is the sixth anniversary of the date of the 2025 Facility Agreement and (ii) the Reserve Tail Date (the “Final Maturity Date”). The Reserve Tail Date is the last day of the calculation period immediately preceding the first calculation period in which the aggregate remaining reserves for all of the borrowing base assets are projected in the then current banking case to be less than 25 % of the initial approved reserves.
The 2025 RBL Facility is secured against certain assets of the Company and the other obligors under the 2025 Facility Agreement. The security package includes security over the shares in the obligors (other than in the Company), hedging agreements, intercompany loans, insurances, offtake agreements relating to the borrowing base assets and project accounts.
The 2025 RBL Facility Agreement contains certain financial covenants, including that, beginning on June 30, 2025 and then as of each March 31 and September 30 until the Final Maturity Date, the ratio of Total Net Indebtedness to EBITDAX (each defined in the 2025 Facility Agreement) for the trailing 12 months shall not exceed 3.0 x. Additionally, following the Baobab FPSO renovation completion date, the debt service coverage ratio for the trailing 12 months commencing on the day immediately following each March 31 and September 30 (and any interim redetermination date) until the Final Maturity Date shall be at least 1.2 :1. The Company also provides a liquidity forecast for the Vaalco Energy Group which shall demonstrate that the total corporate sources equal or exceed the total corporate uses. The liquidity forecast is delivered quarterly during the Baobab FPSO renovation period and otherwise on each redetermination of the banking case and any proposed distribution.
The Company is required to pay a quarterly commitment fee equal to (i) 35 % per annum of the Applicable Margin on the daily amount of the difference (if any) by which the borrowing base amount exceeds the then-outstanding amount of loans, plus (ii) 20 % per annum of the Applicable Margin on the daily amount by which the then-total commitments exceeds the higher of the total outstanding amount of loans and the borrowing base amount. The Company is also required to pay customary technical and modelling bank fees, agency fees and security agent fees. The 2025 Facility Agreement also contains customary information covenants as well as affirmative and negative covenants subject to customary threshold and
F-33
materiality which include, among others, compliance with laws (including environmental laws, sanctions and anti-corruption laws), delivery of quarterly and annual financial statements and compliance certificates, no change of business, no merger and maintenance of corporate existence, field preservations and related contracts relating to the borrowing base assets, maintenance of insurance, entry into certain derivatives contracts which are regulated by the 2025 Facility Agreement and the hedging policy, restrictions on the incurrence of liens, indebtedness, asset dispositions, acquisitions, restricted payments, entry into offtake agreements and other customary covenants. If the aggregate borrowings exceeds 35 % of the lower of (a) the available total commitments and (b) the applicable borrowing base amount, we are also required to enter into commodity price hedge positions covering certain volumes of anticipated future production set out in the banking case. There are other covenants that make the Company’s ability to pay dividends and to enter into certain acquisitions and disposition transactions subject to certain conditions. These covenants are subject to a number of limitations and exceptions.
Additionally, the 2025 RBL Facility Agreement contains customary events of default, including non-payment and borrowing base deficiency, funding shortfall subject to certain liquidity cure rights, breach of financial covenants, misrepresentation, insolvency, changes in ownership or business, litigation, cross default, expropriation of any borrowing base assets, political events, cessation of production and the occurrence of a material adverse effect. The 2025 Facility Agreement also contains events of default related to the failure to complete the Baobab FPSO Renovation by the Baobab FPSO Renovation long stop date determined in the 2025 Facility Agreement and the failure to renew any field license on substantially the same terms three months before the expiration of such field license and if a change of operator occurs. The events of default contains thresholds and remedy periods customary for credit facilities of this nature. If the obligors do not comply with the financial and other covenants relating to non-payment, sanctions, anti-corruption, loans and guarantee or tax in the 2025 Facility Agreement, the Lenders may require immediate payment of all amounts outstanding under the 2025 Facility Agreement and any outstanding unfunded commitments may be terminated. In addition, if any principal amount payable is not paid upon due date, interest shall accrue on the overdue amount from the due date up to the date of the actual payment at an additional interest rate of 2 % per annum, and such interest shall be immediately payable on demand.
Fair Value Measurement
The fair value of the 2025 RBL Facility approximates its respective carrying amount as its interest rate is variable and reflective of current market rates. The fair value measurement for the 2025 RBL Facility represents Level 2 inputs.
13 . LEASES
Under the leasing standard that became effective January 1, 2019 , there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments.
Operating leases
The Company is currently a party to three operating lease agreements for the corporate and Egypt offices and transportation equipment. The remaining lease term for these agreements ranges from 35 to 60 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for certain equipment used in the joint operations includes the gross amount of the lease components.
The transportation equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the number of days or hours the asset is deployed. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities.
Financing leases
The Company is currently a party to several financing lease agreements for the FSO and generators and marine vessels used in the operations of the Etame Marin block. The remaining lease term for these agreements ranges from 1 to 81 months months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included
F-34
in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities.
All leases
For all leases that contain an option to extend the initial lease term, the Company has evaluated whether it is reasonably certain that the Company will extend the lease beyond the initial lease term. When the Company believes it is reasonably certain it will utilize these leased assets beyond the initial lease term, those payments have been included in the calculation of the ROU assets and liabilities. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. The Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.
For the years ended December 31, 2025, 2024 and 2023, the components of the lease costs and supplemental information was as follows:
Year Ended December 31,
2025 2024 2023
Lease cost: (in thousands)
Finance lease cost (1) :
Amortization of lease assets $ 13,558 $ 12,924 $ 10,253
Interest on lease liabilities 5,449 6,274 7,044
Operating lease cost 5,018 5,100 1,403
Short-term lease cost (2)
845 893 6,574
Variable lease cost (3)
1,964 1 653
Total lease expense 26,834 25,192 25,927
Lease costs capitalized 761 — 55
Total lease costs $ 27,595 $ 25,192 $ 25,982
(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,
2025 2024 2023
Other information:
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash flows attributable to finance leases (in thousands) $ 13,289 $ 10,477 $ 7,161
Weighted-average remaining lease term (in years) 6.47 7.36 8.16
Weighted-average discount rate 7.21 % 7.16 % 7.99 %
Operating cash flows attributable to operating leases (in thousands) $ 6,531 $ 2,127 $ 505
Weighted-average remaining lease term (in years) 3.29 4.09 0.67
Weighted-average discount rate 6.53 % 6.14 % 8.45 %
F-35
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,
2025 2024 2023
(in thousands)
Finance lease cost $ 11,179 $ 11,290 $ 10,231
Production expense 4,309 3,517 3,556
General and administrative expense 500 346 196
Lease costs billed to the joint venture owners 10,846 10,039 11,964
Total lease expense 26,834 25,192 25,947
Lease costs capitalized 761 — 35
Total lease costs $ 27,595 $ 25,192 $ 25,982
The following table describes the future maturities of the Company’s operating and financing lease liabilities at December 31, 2025:
Operating Leases Finance Leases
Year (in thousands)
2026 $ 6,646 $ 16,676
2027 5,431 15,216
2028 5,202 11,660
2029 958 11,660
2030 626 12,568
Thereafter — 17,884
18,863 85,664
Less: imputed interest ( 1,936 ) ( 16,289 )
Total lease liabilities $ 16,927 $ 69,375
Under the joint operating agreements, other joint venture owners are obligated to fund approximately $ 41.3 million of the $ 104.5 million in future lease liabilities as of December 31, 2025.
F-36
14. ACCRUED LIABILITIES AND OTHER
Accrued liabilities and other balances were comprised of the following:
As of December 31, 2025
2025 2024
(in thousands)
Accrued accounts payable invoices $ 16,320 $ 48,913
State oil liability 18,244 19,616
Accrued capital expenditures 51,339 8,923
Egypt modernization payable — 9,933
Gabon contractual obligations 3,858 6,977
Accrued wages and other compensation 6,694 4,956
Seismic data 1,155 2,455
Asset retirement obligation, current portion — 1,174
Other 8,834 4,763
Total accrued liabilities and other (a)
$ 106,444 $ 107,710
(a) The table excludes $ 0.2 million of current portion of asset retirement obligations associated with assets held for sale.
15. SHAREHOLDERS ’ EQUITY
Dividend Policy
The following table is a schedule of dividends paid during 2025:
Dividend Payment Date Amount per common share Record Date
March 28, 2025 $ 0.0625 February 28, 2025
June 27, 2025 $ 0.0625 May 23, 2025
September 19, 2025 $ 0.0625 August 22, 2025
December 24, 2025 $ 0.0625 November 21, 2025
Aggregate per share amount paid in 2025 $ 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, 2025 or 2024.
Treasury stock
Please see discussion on the Company’s share buyback program under Note 11. Commitments and Contingencies.
16. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS
The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Board of Directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At December 31, 2025, 483,624 shares were available for future grants.
F-37
For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.
As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the years ended December 31, 2024 and 2023, the Company settled in cash $ 0.2 million and $ 0.4 million, respectively, for SARs no amounts settled for 2025. During the years ended December 31 , 2024 and 2023, the Company received in cash $ 0.4 million and $ 0.7 million, respectively from stock option exercises, no amounts received in 2025.
Year Ended December 31,
2025 2024 2023
(in thousands)
Stock-based compensation - equity awards $ 5,954 $ 4,567 $ 3,338
Stock-based compensation - liability awards — ( 9 ) ( 15 )
Total stock-based compensation $ 5,954 $ 4,558 $ 3,323
Performance restricted stock units
The Company grants shares of its common stock to its executives in the form of shares of performance restricted stock unit (“PSS”) awards. These awards are measured at the fair value of the underlying shares on the date of grant and recognized ratably as compensation expense over a period of three years , vesting in three equal parts on the anniversaries from the date of grant to the extent that the performance hurdles and service condition are met.
In June 2025 , the Company granted 789,976 shares performance-based restricted stock awards (“PSS”) to certain executives of the Company. The awards had a grant date fair value of approximately $ 1.8 million using a Monte Carlo Valuation model. The Company will recognize the entire $ 1.8 million of compensation expense for this award, regardless of whether such conditions are met, over the requisite service period unless units are forfeited during the period.
For each PSS stock award, one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $ 3.86 per share; PSS awards with respect to one-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $ 4.45 per share; and PSS awards with respect to the remaining one-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $ 5.12 per share. These PSS awards contain a requisite service period of 10 years.
During the year ended December 31, 2025, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of the PSS awards under the Monte Carlo model.
Year Ended December 31,
2025
Average expected volatility 68.71 %
Risk-free interest rate 4.40 %
Expected dividend yield 7.44 %
Weighted average grant date fair value - ($/share) $ 2.29
F-38
PSS awards activity associated with the Monte Carlo model for the year ended December 31, 2025 is provided below:
Number of Shares Underlying Options Weighted Average Exercise Price Per
Share Weighted Average Remaining
Contractual Term
(in thousands) (in years)
Unvested at January 1, 2025 — $ —
Granted 790 2.29
Unvested at December 31, 2025 790 $ 2.29 1.75
The intrinsic value of a performance stock option awards is the amount that the current market value of the underlying stock exceeds the exercise price of the award.
As of December 31, 2025 , unrecognized compensation cost related to unvested vesting awards was $ 1.3 million, which is expected to be recognized over a weighted average period of 1.75 years.
Stock options and performance shares
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 share; and performance stock options with respect to the remaining one-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $ 9.09 per share. These awards are option awards that contain a market condition. Compensation cost for such awards is recognized ratably over the derived service period and compensation cost related to awards with a market condition will not be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such performance criteria.
There were no stock option grants during the year ended December 31, 2025.
During the year ended December 31, 2024 and 2023 the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of performance stock options grants under the Monte Carlo model.
Year Ended December 31,
2024 2023
Weighted average exercise price - ($/share) $ 5.96 $ 4.19
Expected life in years 6.7 6.4
Average expected volatility 71 % 68 %
Risk-free interest rate 4.28 % 3.73 %
Expected dividend yield 4.19 % 5.97 %
Weighted average grant date fair value - ($/share) $ 3.27 $ 2.29
F-39
Performance stock options activity associated with the Monte Carlo model for the year ended December 31, 2025 is provided below:
Number of Shares Underlying Options Weighted Average Exercise Price Per
Share Weighted Average Remaining
Contractual Term Aggregate Intrinsic Value
(in thousands) (in years) (in thousands)
Outstanding at January 1, 2025 1,118 $ 5.32
Unvested shares forfeited ( 21 ) 6.41
Outstanding at December 31, 2025 1,097 $ 5.30 7.6 $ 79
Exercisable at December 31, 2025 333 $ 4.21 6.8 $ 79
The intrinsic value of a performance stock option awards is the amount that the current market value of the underlying stock exceeds the exercise price of the award.
As of December 31, 2025 , unrecognized compensation cost related to outstanding performance stock option awards was $ 0.6 million, which is expected to be recognized over a weighted average period of 1.27 years.
The Company’s regular stock options (stock options without a performance condition) awards associated with the Black-Scholes model were all exercised in 2024. The intrinsic value of a stock option is the amount that the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of stock options exercised in 2024 and 2023 was $ 0.5 million and $ 0.6 million, respectively.
Restricted shares
Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally 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, 2025:
Restricted Stock Weighted Average Grant Date Fair Value
(in thousands)
Non-vested shares outstanding at January 1, 2025 1,352 $ 5.41
Awards granted 1,461 3.36
Awards vested ( 623 ) 5.39
Awards forfeited ( 226 ) 4.15
Non-vested shares outstanding at December 31, 2025 1,964 $ 4.03
The total fair value of vested restricted stock awards during 2025, 2024 and 2023 was $ 2.2 million, $ 5.0 million, and $ 1.5 million, respectively. The weighted average grant date fair value per share of restricted stock awards, which vested during 2025, 2024 and 2023, was $ 5.39 , $ 4.42 and $ 3.92 , respectively.
As of December 31, 2025, unrecognized compensation cost related to restricted stock totaled $ 3.8 million and is expected to be recognized over a weighted average period of less than 1.41 years.
RSUs were issued to directors, officers and employees of TransGlobe in the ordinary course of business prior to the TransGlobe Acquisition. Each RSU vests annually over a three-year period.
F-40
RSU activity for the year ended December 31, 2025 is presented in the table below:
Restricted Stock Weighted Average Conversion Date Fair Value
(in thousands)
Non-vested shares outstanding at January 1, 2025 174 $ 5.01
Awards granted 331 3.36
Awards vested ( 82 ) 4.78
Awards forfeited ( 17 ) 3.36
Non-vested shares outstanding at December 31, 2025 406 $ 3.79
The total fair value of vested RSU awards during 2025 was $ 0.3 million. The weighted average grant date fair value per share of RSU, which vested during 2025, was $ 4.78 .
As of December 31, 2025, unrecognized compensation cost related to RSUs totaled $ 1.7 million and is expected to be recognized over a weighted average period of 0.75 years.
During the year ended December 31, 2025, 194,771 shares were added to treasury as a result of tax withholding on the vesting of restricted stock and RSU’s.
PSUs are similar to RSUs except that they originally contained a performance factor affecting the vesting percentage. For the PSUs that remained outstanding following the effective time of the TransGlobe Acquisition, the applicable vesting percentage was determined by the TransGlobe Board of Directors to be 200 % for PSUs granted in 2022 and 2023; and 64.4 % for PSUs granted in 2024. All PSUs granted vest on the third anniversary of their grant date.
PSU activity for the year ended December 31, 2025 is presented in the table below:
Restricted Stock Weighted Average Conversion Date Fair Value
(in thousands)
Non-vested shares outstanding at January 1, 2025 9 $ 4.27
Awards vested ( 9 ) 4.27
Non-vested shares outstanding at December 31, 2025 — $ —
During the year ended December 31, 2025, 3,671 shares were added to treasury shares as a result of tax withholding on the vesting of PSU’s.
DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's Board of Directors. At December 31, 2025 , there are approximately 101,313 DSUs outstanding, which are vested but not converted.
Stock appreciation rights ( “ SARs ” )
SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors. In addition, SARs will
F-41
become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s Board of Directors.
SARs are considered liabilities under US GAAP and the awards are measured at fair value on the grant date and remeasured at fair value until the award is settled.
The intrinsic value of a SAR is the amount that the current market value of the underlying stock exceeds the exercise price of the award. The intrinsic value of SARs exercised in 2024 and 2023 was $ 0.2 million, and 0.4 million respectively. During the years ended December 31, 2025 and 2024, the Company did not grant SARs to employees or directors. On February 28, 2024 , all remaining SAR awards were exercised.
Other Benefit Plans
The Company has adopted forms of change in control agreements for certain named executive officers of the Company as well as a severance plan for its Houston-based non-executive employees. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements will be entitled to receive 100 % and 50 %, respectively, of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months. In addition, certain named executive officers will receive 75 % of their target bonus. Some of the named executive officers are also entitled to severance payments under their employment agreements.
17. RELATED PARTY TRANSACTIONS
VAALCO has entered into various agreements with related parties. The Company paid approximately $ 0.3 million and $ 0.2 million to these related parties for each of the years ended December 31, 2025 and 2024 , respectively. The amounts in both 2025 and 2024 were primarily for contract engineering services paid to an entity owned and controlled by a related party of an officer of the Company.
18. OTHER COMPREHENSIVE INCOME (LOSS)
At December 31, 2025 , the Company’s accumulated other comprehensive loss was $ 0.5 million. All of the Company’s other comprehensive income (loss) arises from the currency translation of VAALCO Energy Canada, Inc. to USD.
The components of accumulated other comprehensive income (loss) are as follows:
Currency Translation Adjustments
(in thousands)
Balance at December 31, 2023 $ 2,880
Amounts reclassified from accumulated other comprehensive loss ( 7,842 )
Balance at December 30, 2024 $ ( 4,962 )
Amounts reclassified from accumulated other comprehensive income 4,464
Balance at December 31, 2025 $ ( 498 )
F-42
19 . 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, 2025 , 2024 and 2023 and long-lived assets and segment assets at December 31, 2025 and 2024 are as follows:
Year Ended December 31, 2025
(in thousands) Gabon Egypt Canada Equatorial Guinea Cote d'Ivoire Corporate and Other Total
Revenues:
Crude oil, natural gas and natural gas liquids sales $ 181,738 $ 139,963 $ 19,174 $ — $ 18,397 $ — $ 359,272
Operating costs and expenses:
Production expense 84,677 53,539 8,458 1,561 9,941 1 158,177
Exploration expense 3,799 2,409 — — 2,706 — 8,914
Depreciation, depletion and amortization 48,739 36,649 13,485 — 10,134 971 109,978
Impairment loss on assets held for sale — — 67,224 — — — 67,224
General and administrative expense 1,684 545 136 282 2,138 28,304 33,089
Credit (recovery) losses and other ( 792 ) ( 228 ) — 1,126 — — 106
Total operating costs and expenses 138,107 92,914 89,303 2,969 24,919 29,276 377,488
Other operating income (expense), net 18 — — — ( 2,409 ) — ( 2,391 )
Operating income (loss) 43,649 47,049 ( 70,129 ) ( 2,969 ) ( 8,931 ) ( 29,276 ) ( 20,607 )
Other income (expense):
Derivative instruments loss, net — — — — — 2,876 2,876
Interest expense, net ( 3,443 ) ( 862 ) — — ( 3,117 ) ( 821 ) ( 8,243 )
Bargain purchase gain — — — — — — —
Other income (expense), net ( 1,096 ) 155 444 ( 5 ) 325 ( 418 ) ( 595 )
Total other income (expense), net ( 4,539 ) ( 707 ) 444 ( 5 ) ( 2,792 ) 1,637 ( 5,962 )
Income (loss) before income taxes 39,110 46,342 ( 69,685 ) ( 2,974 ) ( 11,723 ) ( 27,639 ) ( 26,569 )
Income tax (benefit) expense 17,959 21,358 — — ( 22,631 ) ( 1,864 ) 14,822
Net income (loss) $ 21,151 $ 24,984 $ ( 69,685 ) $ ( 2,974 ) $ 10,908 $ ( 25,775 ) $ ( 41,391 )
Consolidated capital expenditures $ 61,739 $ 28,768 $ 1,588 $ 607 $ 143,186 $ 526 $ 236,414
F-43
Year Ended December 31, 2024
(in thousands) Gabon Egypt Canada Equatorial Guinea Côte 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 (benefit) expense 48,026 30,648 — — 4,229 ( 1,596 ) 81,307
Net income (loss) $ 36,171 $ 24,466 $ 1,863 $ ( 2,164 ) $ 12,143 $ ( 13,989 ) $ 58,490
Consolidated capital expenditures $ 22,579 $ 11,364 $ 25,828 $ 641 $ 44,435 $ 4,592 $ 109,439
F-44
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 loss, net — — — — 232 232
Interest income, net ( 5,563 ) ( 2,110 ) ( 4 ) — 1,225 ( 6,452 )
Bargain purchase gain measurement period adjustment — — — — ( 1,412 ) ( 1,412 )
Other income (expense), net ( 820 ) — 2 ( 6 ) ( 70 ) ( 894 )
Total other income (expense), net ( 6,383 ) ( 2,110 ) ( 2 ) ( 6 ) ( 25 ) ( 8,526 )
Income (loss) before income taxes 105,447 60,754 7,537 ( 2,411 ) ( 21,196 ) 150,131
Income tax (benefit) expense 50,692 32,859 — — 6,226 89,777
Net income (loss) $ 54,755 $ 27,895 $ 7,537 $ ( 2,411 ) $ ( 27,422 ) $ 60,354
Consolidated capital expenditures $ 17,011 $ 37,866 $ 16,809 $ — $ 950 $ 72,636
(in thousands) Gabon Egypt Canada (a)
Equatorial Guinea Côte d'Ivoire Corporate and Other Total
Long-lived assets:
As of December 31, 2025 $ 177,030 $ 138,839 $ — $ 11,248 $ 254,307 $ 4,671 $ 586,095
As of December 31, 2024 $ 153,576 $ 149,129 $ 104,891 $ 10,641 $ 114,756 $ 5,110 $ 538,103
(a) At December 31, 2025, the Company classified $ 31.8 million of net Crude oil, natural gas and NGLs properties as “Noncurrent Ass ets held for sale” on the Consolidated Balance Sheet.
(in thousands) Gabon Egypt Canada Equatorial Guinea Côte d'Ivoire Corporate and Other Total
Total assets:
As of December 31, 2025 $ 315,787 $ 182,023 $ 35,982 $ 13,631 $ 283,768 $ 82,184 $ 913,375
As of December 31, 2024 $ 300,568 $ 269,905 $ 113,310 $ 12,331 $ 187,264 $ 71,572 $ 954,950
F-45
20. SUBSEQUENT EVENTS
In February 2026, the Company became the operator with a 60 % working interest in the Kossipo field on the CI-40 Block with a field development plan to be completed in the second half of 2026.
SUPPLEMENTAL INFORMATION ON CRUDE OIL, NATURAL GAS AND NGLs PRODUCING ACTIVITIES (UNAUDITED)
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 as well as, prior to the Canada Asset Divestment (defined below), producing properties in Canada.
In December 2025, the Company’s Board of Directors approved the sale of the Company’s oil and gas properties in Canada. As of December 31, 2025, certain assets and liabilities associated with our Canada Asset Divestment were classified as held for sale on our Consolidated Balance Sheet. On February 4, 2026, the Company entered into an asset purchase agreement to sell all of our operating assets in Canada. The sale was completed on February 16, 2026 with an effective date of February 1, 2026 (the “Canada Asset Divestment”). As of December 31, 2025, all of our proved developed and proved undeveloped reserves in Canada are attributed to assets held for sale.
Our reserves information was evaluated by the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). Prior to 2025, reserves information for Canada was independently evaluated by GLJ Ltd. (“GLJ”). The proved reserve quantities are calculated based on our NRI.
Costs Incurred for Acquisition, Exploration and Development Activities
Costs incurred during the year: Gabon Egypt Canada Cote d'Ivoire Total
Year Ended December 31, 2025 (in thousands)
Exploration costs - expensed $ 3,799 $ 2,409 $ — $ 2,706 $ 8,914
Exploration costs - capitalized — 1,201 — — 1,201
Acquisition of properties — — — 3,034 3,034
Development costs 61,739 27,567 1,588 143,186 234,080
Total $ 65,538 $ 31,177 $ 1,588 $ 148,926 $ 247,229
Gabon Egypt Canada Cote d'Ivoire Total
Year Ended December 31, 2024 (in thousands)
Exploration costs - expensed $ — $ 48 $ — $ — $ 48
Acquisition of properties — — — 107,089 107,089
Development costs 22,579 11,364 25,828 44,435 104,206
Total $ 22,579 $ 11,412 $ 25,828 $ 151,524 $ 211,343
Gabon Egypt Canada Total
Year Ended December 31, 2023 (1)
(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
(1) For Cote d'Ivoire, all activity pertains to the period from April 30, 2024 to December 31, 2024 related to the Svenska Acquisition.
F-46
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,
2025 2024
Capitalized costs: (in thousands)
Properties not being amortized $ 348,641 $ 155,825
Properties being amortized 1,147,433 1,588,699
Total capitalized costs $ 1,496,074 $ 1,744,524
Less accumulated depletion, amortization and impairment (884,747) (1,214,465)
Net capitalized costs $ 611,327 $ 530,059
Results of Operations for crude oil, natural gas and NGLs Producing Activities
Gabon Egypt Canada Cote d'Ivoire Total
Year Ended December 31, 2025 (In thousands)
Revenues $ 181,738 $ 139,963 $ 19,174 $ 18,397 $ 359,272
Production costs and other expense (1)
(84,677) (53,539) (8,458) (9,941) (156,615)
Depreciation, depletion, amortization (48,739) (36,649) (13,485) (10,134) (109,007)
Impairment loss on assets held for sale — — (67,224) — (67,224)
Exploration expenses (3,799) (2,409) — (2,706) (8,914)
Other operating expense 18 — — (2,409) (2,391)
Income tax benefit (expense) (22,748) (21,813) — 12,525 (32,036)
Results from crude oil and natural gas producing activities $ 21,793 $ 25,553 $ (69,993) $ 5,732 $ (16,915)
Gabon Egypt Canada Cote d'Ivoire Total
Year Ended December 31, 2024 (2)
(In thousands)
Crude oil and natural gas sales $ 205,954 $ 145,966 $ 31,986 $ 95,082 $ 478,988
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
(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.
F-47
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, 2023 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 — — 251 — 251
Revisions of previous estimates 4,782 1,441 (569) 1,018 6,672
Balance at December 31, 2024 11,063 9,448 2,765 15,252 38,528
Production (2,535) (2,730) (214) (111) (5,590)
Purchase of reserves — — — — —
Extensions and discoveries 1,195 34 — — 1,229
Revisions of previous estimates 278 1,862 (209) 1,870 3,801
Balance at December 31, 2025 10,001 8,614 2,342 17,011 37,968
Oil
Gabon
(MBbls) Egypt
(MBbls) Canada
(MBbls) Cote d'Ivoire
(MBbls) Total
(MBbls)
Year-end proved developed reserves:
2025 5,287 8,177 1,179 — 14,643
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
Year-end proved undeveloped reserves:
2025 4,714 437 1,163 17,011 23,325
2024 4,233 486 1,286 15,134 21,139
2023 1,011 451 2,122 — 3,584
2022 — 576 1,885 — 2,461
F-48
Natural Gas
Proved reserves: Gabon
(MMcf) Egypt
(MMcf) Canada
(MMcf) Cote d'Ivoire
(MMcf) Total
(MMcf)
Balance at January 1, 2023 — — 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 — — 876 — 876
Revisions of previous estimates — — (196) (253) (449)
Balance at December 31, 2024 — — 16,080 6,551 22,631
Production — — (1,449) — (1,449)
Extensions and discoveries — — — — —
Revisions of previous estimates — — (2,422) 403 (2,019)
Balance at December 31, 2025 — — 12,209 6,954 19,163
Natural Gas
Gabon
(MMcf) Egypt
(MMcf) Canada
(MMcf) Cote d'Ivoire
(MMcf) Total
(MMcf)
Year-end proved developed reserves:
2025 — — 9,059 — 9,059
2024 — — 10,490 47 10,537
2023 — — 9,011 — 9,011
2022 — — 11,023 — 11,023
Year-end proved undeveloped reserves:
2025 — — 3,150 6,954 10,104
2024 — — 5,590 6,504 12,094
2023 — — 7,921 — 7,921
2022 — — 5,516 — 5,516
F-49
NGLs
Proved reserves: Gabon
(MBbls) Egypt
(MBbls) Canada
(MBbls) Cote d'Ivoire
(MBbls) Total
(MBbls)
Balance at January 1, 2023 — — 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 — — 142 — 142
Revisions of previous estimates — — 68 — 68
Balance at December 31, 2024 — — 2,680 — 2,680
Production — — (212) — (212)
Extensions and discoveries — — — — —
Revisions of previous estimates — — (687) — (687)
Balance at December 31, 2025 — — 1,781 — 1,781
NGLs
Gabon
(MBbls) Egypt
(MBbls) Canada
(MBbls) Cote d'Ivoire
(MBbls) Total
(MBbls)
Year-end proved developed reserves:
2025 — — 1,329 — 1,329
2024 — — 1,744 — 1,744
2023 — — 1,449 — 1,449
2022 — — 1,855 — 1,855
Year-end proved undeveloped reserves:
2025 — — 452 — 452
2024 — — 936 — 936
2023 — — 1,289 — 1,289
2022 — — 942 — 942
F-50
Total Reserves (1)
Proved reserves: Gabon
(MBoe) Egypt
(MBoe) Canada
(MBoe) Cote d'Ivoire
(MBoe) Total
(MBoe)
Balance at January 1, 2023 10,219 8,577 9,161 — 27,957
Production (3,197) (2,771) (859) — (6,827)
Purchase of reserves — — — — —
Extensions and discoveries — 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 — — 539 — 539
Revisions of previous estimates 4,782 1,441 (534) 974 6,663
Balance at December 31, 2024 11,063 9,448 8,126 16,381 45,018
Production (2,535) (2,730) (667) (111) (6,043)
Purchase of reserves — — — — —
Extensions and discoveries 1,195 34 — — 1,229
Revisions of previous estimates 278 1,862 (1,301) 1,940 2,779
Balance at December 31, 2025 10,001 8,614 6,158 18,210 42,983
(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:
2025 5,287 8,177 4,018 — 17,482
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
Year-end proved undeveloped reserves:
2025 4,714 437 2,140 18,210 25,501
2024 4,233 486 3,154 16,255 24,128
2023 1,011 451 4,731 — 6,193
2022 — 576 3,746 — 4,322
(1) To convert Natural Gas to MBoe, MMcf is divided by 6 for Canada reserves, and MMcf is divided by 5.8 for Cote d'Ivoire reserves.
Year Ended December 31, 2025
Revisions
During 2025, the Company had net positive revisions of prior estimates of 2.8 MMBoe. These upward revisions include an increase of 1.9 MMBoe from our Egypt segment resulting from a combination of continued development activity including active in-field drilling, workovers as well as improved, forecasted well performance. In addition, we had an increase of 1.9 MMBoe from our Cote d’Ivoire segment which reflects improved recovery based on technical analysis of the upcoming Phase 5 drilling campaign. The Gabon segment also contributed to an increase of 0.3 MMBoe based on improved production performance. The upward revisions were offset by negative revisions of 1.3 MMBoe in Canada due to wells that were not reasonably expected to be developed within the five-year timeframe in accordance with the SEC guidance.
Extensions and discoveries
During 2025, the Company added 1.2 MMBoe of proved reserves through extensions, discoveries, and other additions related to the Phase 3 drilling campaign in Gabon.
F-51
Year Ended December 31, 2024
Purchases of reserves in place
For the balance at December 31, 2024, purchases of reserves in place included 16.5 MMBoe of proved reserves in Cote d'Ivoire, associated with our acquisition of Svenska Petroleum Exploration Aktiebolag (“Svenska”), and as a result, Svenska’s primary asset: a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40.
Extensions and discoveries
For the balance at December 31, 2024, extensions and discoveries included 0.5 MMBoe of proved reserves in Canada, primarily related to the drilling of new wells.
Revisions
In 2024, operations in Gabon had 4.8 MMBoe of reserves added through positive revisions of previous estimates mainly due to performance and development activities. For Egypt, we had 1.4 MMBoe of reserves added through positive revisions of previous estimates primarily as a result of our workover programs. For Canada, we had 0.5 MMBoe of negative revisions of previous estimates primarily due to performance adjustments of existing wells. For the balance at December 31, 2024, operations in Cote d'Ivoire included 1.0 MMBoe in positive revisions of reserves due to improved field performance.
Year Ended December 31, 2023
Revisions
In 2023, operations in Gabon had 2.0 MMBoe of reserves added through positive revisions of previous estimates. 2.8 MMBoe of the positive revisions were due to performance offset by 0.8 MMBoe of negative revisions through price. For Egypt at December 31, 2023, 4.7 MMBoe of reserves were added through positive revisions of previous estimates. 5.3 MMBoe of the positive revisions were due to performance offset by 0.6 MMBoe of negative revisions through price. For the balance at December 31, 2023, operations in Canada included 1.2 MMBoe in negative revisions of reserves due to performance adjustments of existing wells.
Extensions and discoveries
For the balance at December 31, 2023, extensions and discoveries included 0.1 MMBoe of proved reserves in Egypt, primarily related to operational improvements and the drilling of new wells and 1.9 MMBoe of proved reserves in Canada, primarily related to the drilling of new wells.
In accordance with the guidelines of the SEC, the Company does not book proved reserves on discoveries until such time as a development plan has been prepared for the discovery indicating that the development well will be drilled within five years from the date of its initial booking. 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, 2025, 2024 and 2023.
International
(In thousands) Gabon Egypt Canada Cote d'Ivoire Total
Year Ended December 31, 2025
Future cash inflows $ 666,072 $ 556,434 $ 197,628 $ 1,301,697 $ 2,721,831
Future production costs (390,226) (302,960) (82,400) (445,893) (1,221,479)
Future development costs (1) (156,136) (53,308) (59,664) (348,759) (617,867)
Future income tax expense (86,489) (59,725) — (125,346) (271,560)
Future net cash flows 33,221 140,441 55,564 381,699 610,925
Discount to present value at 10% annual rate (1,660) (22,389) (27,793) (149,074) (200,916)
Standardized measure of discounted future net cash flows $ 31,561 $ 118,052 $ 27,771 $ 232,625 $ 410,009
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
(1) Includes costs expected to be incurred to abandon the properties, where applicable.
International income taxes represent amounts payable to the Governments of Gabon and Cote d’Ivoire on Profit Oil as final payment of corporate income taxes, and domestic income taxes (including other expenses treated as taxes).
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,
2025 2024 2023
(in thousands)
Balance at beginning of period $ 379,400 $ 341,934 $ 624,465
Sales of crude oil and natural gas, net of production costs (192,861) (316,667) (296,209)
Net changes in prices and production costs (279,298) 18,385 (210,703)
Extensions and discoveries 5,542 9,156 28,849
Revisions of previous quantity estimates 93,369 145,177 139,856
Purchases — 175,849 —
Changes in estimated future development costs 18,844 (94,003) (92,641)
Development costs incurred during the period 201,533 28,676 —
Accretion of discount 37,940 45,917 62,447
Net change of income taxes 139,391 21,053 77,757
Change in production rates (timing) and other 6,149 3,923 8,113
Balance at end of period $ 410,009 $ 379,400 $ 341,934
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.
F-54
For 2025 and 2024, the average of such prices used for our reserve estimate were as follows:
Year Ended December 31,
2025 2024
Crude Oil ($/Bbl)
Gabon $ 66.60 $ 81.08
Egypt $ 57.66 $ 65.48
Cote d'Ivoire $ 68.95 $ 79.70
Canada $ 61.61 $ 69.12
Natural Gas ($/Mcf)
Cote d'Ivoire $ 2.77 $ 2.77
Canada $ 1.07 $ 0.95
Natural Gas Liquids ($/Bbl)
Canada
Ethane $ 2.90 $ 3.52
Propane $ 19.67 $ 19.46
Butane $ 25.88 $ 30.68
Condensates $ 62.44 $ 69.59
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. Please see further discussion in Note 6. Revenue.
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
F-55
term of 25 years. At December 31, 2025, 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 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