VAALCO ENERGY INC /DE/ 10-K

Item 9A. Controls and Procedures   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 the Chief Executive Officer and Chief Financial Officer, 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 principal executive officer and principal financial officer, 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 principal executive officer and principal financial officer have concluded that, due to the material weaknesses described below, the Company’s disclosure controls and procedures were not effective as of December 31, 2022 at the reasonable assurance level.     80 Table of Contents   MANAGEMENT ’ S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING   Our management, including our Chief Executive Officer and our Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Under the supervision and with the participation of management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting using the criteria set forth in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). On October 13, 2022, the Company completed the acquisition of TransGlobe (see Note 4 to the Consolidated Financial Statements), which operated under its own set of internal controls. As permitted by the SEC Staff interpretive guidance for newly acquired businesses, the Company’s management excluded TransGlobe from the evaluation of internal control over financial reporting as of December 31, 2022. Since completion of the acquisition, the Company transitioned certain TransGlobe processes to the Company’s internal control processes and added other internal controls over significant processes specific to the acquisition and to post-acquisition activities, including internal controls associated with the valuation of certain assets acquired and liabilities assumed in the acquisition. The Company will continue the process of integrating internal controls over financial reporting for TransGlobe and plans to incorporate TransGlobe in the evaluation of internal controls over financial reporting beginning in the second quarter of 2023. TransGlobe represented 48% of the Company’s consolidated total assets as of December 31, 2022, while its revenues comprised 13% of the Company’s consolidated sales and its net income comprised 19% of the Company’s net income for the year ended December 31, 2022.   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. 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. Based on the evaluation and due to the material weaknesses described below, our management concluded that, the Company’s internal control over financial reporting was not effective as of December 31, 2022. A material weakness in internal controls 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 our annual or interim financial statements will not be prevented or detected on a timely basis.   We have identified the following material weaknesses:    Accounting for Leases We did not design and maintain effective controls over the change in method of accounting for leases Accounting Standard Update No. 2016-02, Leases (ASC 842). The Company’s controls over the application of the proper accounting treatment for leases related to discount rates used and the identification and communication when a lease was modified were not effective, as the discount rate and a modification were not properly reflected in the historical accounting analysis. This material weakness could have resulted in improper balances related to lease assets and lease liabilities in our fiscal 2022 consolidated financial statements.   Complex Accounting for Business Combinations We did not design and maintain effective controls over the accounting for our acquisition with TransGlobe, including a lack of sufficient precision in the performance of reviews of the analyses supporting the purchase price allocation accounting and other acquisition related entries with adequate documentation to provide sufficient evidence of operating effectiveness of associated management review controls. This material weakness could have resulted in material adjustments to the initial purchase price recorded in our fiscal 2022 consolidated financial statements.    81 Table of Contents   Financial Reporting and Consolidation We did not design and maintain an effective controls over the preparation of consolidated financial statements and consolidation of our subsidiaries as it relates to our Canadian and Egyptian operations, which were acquired as part of the TransGlobe acquisition. We did not provide sufficient and appropriate documentation related to demonstrating adequate review of the combined company consolidation. This material weakness could have resulted in material adjustments to the consolidated financial statements of the combined company in fiscal 2022.   Accounting for Income Taxes We did not design and maintain effective controls over the accounting for income taxes principally related to review over tax workpapers. This material weakness resulted in adjustments to the current income taxes, and deferred taxes, in our fiscal year 2022 consolidated financial statements.   After giving full consideration to these material weaknesses, and the additional analyses and other procedures that we performed to ensure that our consolidated financial statements included in this Annual Report were prepared in accordance with U.S. GAAP, our management has concluded that our consolidated financial statements present fairly, in all material respects, our financial position, results of operations and cash flows for the periods disclosed in conformity with US GAAP.   Remediation Process   Following the identification of the material weaknesses described above, and with the oversight of the Audit Committee, we have commenced a process to remediate the underlying causes of the material weaknesses described above, enhance the control environment and strengthen our internal control over financial reporting. The steps that have been taken or that the Company intends to take with respect to remediation are as follows:     ● We plan to devote additional resources towards engaging personnel to acquire and enhance relevant public company financial reporting and accounting skillsets, with a focus in the areas identified above.   ● We plan to redesign our control framework involving identification and communication concerning certain accounting and business operations procedures and controls to achieve, accurate and timely financial accounting, reporting and necessary disclosures.   ● We plan to enhance adequate documentary evidence for relevant management review controls over certain business processes including precision of review and evidence of review procedures performed to demonstrate effective operation of such controls.   As we continue to evaluate and work to improve our internal control over financial reporting, we may take additional measures to address control deficiencies, or we may modify certain of the remediation measures described above. The material weaknesses will not be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.   Our internal control over financial reporting as of December 31, 2022 has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this Annual Report. BDO USA, 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, there have been no changes in our internal control over financial reporting during the three months ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.      Item 9B. Other Information   None.   82 Table of Contents   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 the proxy statement for our 2023 annual meeting, which will be filed with the SEC within 120 days of December 31, 2022, and that is incorporated herein by reference.   Item 11. Executive Compensation   Information required by this item will be included in the proxy statement for our 2023 annual meeting, which will be filed with the SEC within 120 days of December 31, 2022, 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 the proxy statement for our 2023 annual meeting, which will be filed with the SEC within 120 days of December 31, 2022, and which is incorporated herein by reference.    The following table provides information as of December 31, 2022 regarding the number of shares of common stock that may be issued under our compensation plans. Please refer to Note 17 to the 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     830,388     $ 2.97       3,870,496   Total     830,388     $ 2.97       3,870,496     Item 13. Certain Relationships and Related Transactions, and Director Independence   Information required by this item will be included in the proxy statement for our 2023 annual meeting, which will be filed with the SEC within 120 days of December 31, 2022, and that is incorporated herein by reference.     Item 14. Principal Accountant Fees and Services   Information required by this item will be included in the proxy statement for our 2023 annual meeting, which will be filed with the SEC within 120 days of December 31, 2022, and that is incorporated herein by reference.   83 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 ( BDO USA, LLP ; Houston, Texas ; PCAOB ID No. 243 ) F-1 Report of Independent Registered Public Accounting Firm Over Internal Controls over Financial Reporting (BDO USA, LLP; Houston, Texas; PCAOB ID No. 243) F-2 Consolidated Balance Sheets as of December   31, 2022 and 2021 F-3 Consolidated Statements of Operations and Comprehensive Income (Loss) for the   Years Ended December   31, 2022, 2021 and 2020 F-4 Consolidated Statements of Shareholders ’  Equity for the Years Ended December   31, 2022, 2021 and 2020 F-5 Consolidated Statements of Cash Flows for the   Years Ended December   31, 2022, 2021 and 2020 F-6 Notes to the Consolidated Financial Statements F-8 Supplemental Information On crude oil, natural gas and NGLs Producing Activities (Unaudited) F-52       (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). 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 13, 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 Description of securities (filed as Exhibit 4.1 to the Company’s Current Report on Form 10-K filed on March 9, 2020, and incorporated herein by reference). 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). 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).   84 Table of Contents   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 Appreciate 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* 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). 10.19* 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). 10.20* 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). 10.21* 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). 10.21.1* 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). 10.21.2 *(a) Amendment No. 2 to Employment Agreement, by and between VAALCO Energy, Inc. and George Maxwell, effective as of November 23, 2022.   85 Table of Contents   10.22* Employment Agreement, dated as of May 25, 2021, by and between VAALCO Energy, Inc. and Michael Silver (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 28, 2021, and incorporated herein by reference). 10.22.1* First Amendment to Employment Agreement, dated as of August 30, 2022, by and between VAALCO Energy, Inc. and Michael Silver (filed as Exhibit 10.1 to the Company's Current Report on form 10-Q filed on November 8th, 2022, 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 *(a) Amendment No. 2 to Employment Agreement, effective as of November 23, 2022, by and between VAALCO Energy, Inc. and Ronald Bain. 10.24 *(a) TransGlobe Energy Corporation Amended and Restated Deferred Share Unit Plan. 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 (a) 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. 10.25.2 (a) Second Amendment to Bareboat Charter, by and between VAALCO Gabon SA and Ocean Cloud Navigation Inc., dated as of March 22, 2023. 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 by reference herein). 10.26.1 (a) 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. 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 by reference herein). 10.27.1 (a) 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. 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 by reference herein) 10.28.1 (a) 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. 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 by reference herein) 10.30 Facility Agreement, by and among VAALCO Energy, Inc., VAALCO Gabon (Etame), Inc., VAALCO Gabon, SA, Glencore Energy UK Ltd., the Law Debenture Trust Corporation P.L.C., and the other financial institutions named therein, dated May 16, 2022 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on August 10, 2022, and incorporated herein by reference). 10.31 Crude Oil Sale and Marketing Agreement, by and between VAAALCO Gabon S.A. and Glencore Energy UK Ltd., dated May 20, 2022 (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on August 10, 2022, and incorporated herein by reference). 10.32 *(a) Separation Agreement, by and between VAALCO Energy, Inc. and David DesAutels, dated as of March 8, 2023 10.33 *(a) Consulting Agreement between VAALCO Energy and David DesAutels, dated as of March 8, 2023.   86 Table of Contents   21.1 (a) List of subsidiaries of the Company. 23.1 (a) Consent of BDO USA, LLP. 23.2 (a) Consent of Netherland, Sewell & Associates, Inc. — Independent Petroleum Engineers. 23.3 (a) Consent of GLJ Ltd. — Independent Petroleum Engineers. 31.1 (a) Sarbanes-Oxley Section 302 certification of Principal Executive Officer. 31.2 (a) Sarbanes-Oxley Section 302 certification of Principal Financial Officer. 32.1 (b) Sarbanes-Oxley Section 906 certification of Principal Executive Officer. 32.2 (b) Sarbanes-Oxley Section 906 certification of Principal Financial Officer. 99.1 (a) Report of Netherland, Sewell & Associates, Inc. (International Properties). 99.2 (a) Report of GLJ Ltd. 101.INS(a) Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 101.SCH(a) Inline XBRL Taxonomy Schema Document. 101.CAL(a) Inline XBRL Calculation Linkbase Document. 101.DEF(a) Inline XBRL Definition Linkbase Document. 101.LAB(a) Inline XBRL Label Linkbase Document. 101.PRE(a) Inline XBRL Presentation Linkbase Document. 104(a) Cover Page Interactive Data File (formatted as Inline XBRL and Contained in Exhibit 101).   ___________________________________ (a) Filed herewith (b) Furnished herewith * Management contract or compensatory plan or arrangement    87 Table of Contents   Item 16. Form 10-K Summary   None.   88 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 April 6, 2023   Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the 6th day of April 2023, 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/ Jason Doornik   Chief Accounting Officer (Principal Accounting Officer)   Jason Doornik             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/ David Cook   Director   David Cook             By: /s/ Edward LaFehr   Director   Edward LaFehr             By: /s/ Timothy Marchant   Director   Timothy Marchant       89 Table of Contents     Report of Independent Registered Public Accounting Firm   Shareholders and Board of Directors VAALCO Energy, Inc. Houston, Texas   Opinion on the Consolidated Financial Statements   We have audited the accompanying consolidated balance sheets of VAALCO Energy, Inc. (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 , in conformity with accounting principles generally accepted in the United States of America.   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, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated April 6, 2023 expressed an adverse opinion thereon.   Basis for Opinion   These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our 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 Matter   The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.   Valuation and Recognition of Crude Oil and Natural Gas Properties Acquired in TransGlobe Energy Corporation Acquisition   As described in Notes 2 and 4 to the consolidated financial statements, on October 13, 2022 the Company completed its acquisition of TransGlobe Energy Corporation (“TransGlobe”) for purchase consideration of $274.1 million. The transaction qualified as a business combination under ASC 805, Business Combinations, and as such all assets and liabilities associated with the TransGlobe acquisition were recorded at their acquisition date fair values. As a result of the acquisition, the Company recognized wells, platforms and other production facilities of $243.7 million and undeveloped acreage of $30.2 million, which are included within crude oil and natural gas properties within the Company’s consolidated balance sheet.    We identified the estimation of the fair value of wells, platforms and other production facilities and undeveloped acreage acquired from TransGlobe as a critical audit matter. The Company, with the assistance of outside consultants, used significant judgment to develop the estimated fair value of reserve quantities factoring in specific risk adjustment factors based on reserve category and the Company’s weighted average cost of capital. Auditing these assumptions involved especially challenging and subjective auditor judgment and increased effort, including the involvement of professionals with specialized knowledge and skill in valuation.    The primary procedures we performed to address this critical audit matter included:     ● Assessing the competence, capability and objectivity of the outside consultants engaged by the Company to assist in estimating the fair value of the acquired wells, platforms and other production facilities and undeveloped acreage and evaluating the valuation methodology selected.         ● Utilizing professionals with specialized knowledge and skill in valuation to assist in assessing the reasonableness of risk adjustments based on reserve category and the weighted average cost of capital utilized by management.   /s/ BDO USA, LLP   We have served as the Company's auditor since 2016.   Houston, Texas   April 6, 2023     F-1 Table of Contents   Report of Independent Registered Public Accounting Firm   Shareholders and Board of Directors VAALCO Energy, Inc. Houston, Texas   Opinion on Internal Control over Financial Reporting   We have audited VAALCO Energy, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.   We do not express an opinion or any other form of assurance on management’s statements referring to any corrective actions taken by the Company after the date of management’s assessment.   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, 2022 and 2021, the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as “the financial statements”) and our report dated April 6, 2023 expressed an unqualified opinion thereon.   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 Item 9A, Management’s 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 U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.   We conducted our audit of internal control over financial reporting 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 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.   As indicated in the accompanying Item 9A, Management’s Annual Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of TransGlobe Energy Corporation (“TransGlobe”), which was acquired on October 13, 2022, and which is included in the consolidated balance sheets of the Company as of December 31, 2022, and the related consolidated statements of income and comprehensive income (loss), stockholders’ equity, and cash flows for the year then ended. TransGlobe constituted 48% and 62% of total assets and net assets, respectively, as of December 31, 2022, and 13% and 19% of revenues and net income, respectively, for the year then ended. Management did not assess the effectiveness of internal control over financial reporting of TransGlobe because of the timing of the acquisition which was completed on October 13, 2022. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of TransGlobe.   A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. Material weaknesses regarding management’s failure to design and maintain effective controls over accounting for leases, complex accounting for business combinations, accounting for income taxes and financial reporting and consolidation have each been identified and described in management’s assessment. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2022 consolidated financial statements, and this report does not affect our report dated April 6, 2023 on those consolidated financial statements.   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/ BDO USA, LLP   Houston, Texas    April 6, 2023   F-2 Table of Contents   VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS       As of December 31, 2022     As of December 31, 2021       (in thousands)   ASSETS                 Current assets:                 Cash and cash equivalents   $ 37,205     $ 48,675   Restricted cash     222       79   Receivables:                 Trade, net     52,147       22,464   Accounts with joint venture owners, net of allowance of $ 0.0 million in both periods presented     15,830       345   Foreign income taxes receivable     2,769       —   Other, net     68,519       9,977   Crude oil inventory     3,335       1,593   Prepayments and other     20,070       5,156   Total current assets     200,097       88,289                     Crude oil and natural gas properties, equipment and other - successful efforts method, net     495,272       94,324   Other noncurrent assets:                 Restricted cash     1,763       1,752   Value added tax and other receivables, net of allowance of $ 8.7 million and $ 5.7 million, respectively     7,150       5,536   Right of use operating lease assets     2,777       10,227   Right of use finance lease assets     90,698       —   Deferred tax assets     35,432       39,978   Abandonment funding     20,586       21,808   Other long-term assets     1,866       1,176   Total assets   $ 855,641     $ 263,090   LIABILITIES AND SHAREHOLDERS' EQUITY                 Current liabilities:                 Accounts payable   $ 59,886     $ 18,797   Accounts with joint venture owners     —       3,233   Accrued liabilities and other     91,392       49,444   Operating lease liabilities - current portion     2,314       9,642   Finance lease liabilities - current portion     7,811       —   Foreign income taxes payable     —       3,128   Current liabilities - discontinued operations     687       13   Total current liabilities     162,090       84,257   Asset retirement obligations     41,695       33,949   Operating lease liabilities - net of current portion     686       587   Finance lease liabilities - net of current portion     78,248       —   Deferred tax liabilities     81,223       —   Other long-term liabilities     25,594       —   Total liabilities     389,536       118,793   Commitments and contingencies (Note 12)                     Shareholders’ equity:                 Preferred stock, $ 25 par value; 500,000 shares authorized, none issued     —       —   Common stock, $ 0.10 par value; 160,000,000 and 100,000,000 shares authorized, 119,482,680 and 69,562,774 shares issued, 107,852,857 and 58,623,451 shares outstanding, respectively     11,948       6,956   Additional paid-in capital     353,606       76,700   Accumulated other comprehensive income     1,179       —   Less treasury stock, 11,629,823 and 10,939,323 shares, respectively, at cost     ( 47,652 )     ( 43,847 ) Retained earnings     147,024       104,488   Total shareholders' equity     466,105       144,297   Total liabilities and shareholders' equity   $ 855,641     $ 263,090     See notes to consolidated financial statements.   F-3 Table of Contents   VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)       Year Ended December 31,       2022     2021     2020       (in thousands, except per share amounts)   Revenues:                         Crude oil, natural gas and natural gas liquids sales   $ 354,326     $ 199,075     $ 67,176   Operating costs and expenses:                         Production expense     112,661       81,255       37,315   FPSO demobilization     8,867       —       —   Exploration expense     258       1,579       3,588   Depreciation, depletion and amortization     48,143       21,060       9,382   Impairment of proved crude oil and natural gas properties     —       —       30,625   General and administrative expense     10,077       14,766       10,695   Bad debt expense and other     3,082       875       1,165   Total operating costs and expenses     183,088       119,535       92,770   Other operating income (expense), net     38       ( 440 )     ( 1,669 ) Operating income (loss)     171,276       79,100       ( 27,263 ) Other income (expense):                         Derivative instruments gain (loss), net     ( 37,812 )     ( 22,826 )     6,577   Interest income (expense), net     ( 2,034 )     10       155   Other income (expense), net     ( 8,048 )     3,494       129   Total other income (expense), net     ( 47,894 )     ( 19,322 )     6,861   Income (loss) from continuing operations before income taxes     123,382       59,778       ( 20,402 ) Income tax expense (benefit)     71,420       ( 22,156 )     27,681   Income (loss) from continuing operations     51,962       81,934       ( 48,083 ) Loss from discontinued operations, net of tax     ( 72 )     ( 98 )     ( 98 ) Net income (loss)   $ 51,890     $ 81,836     $ ( 48,181 ) Other comprehensive income (loss)                         Currency translation adjustments     1,179       —       —   Comprehensive income (loss)   $ 53,069     $ 81,836     $ ( 48,181 )                           Basic net income (loss) per share:                         Income (loss) from continuing operations   $ 0.74     $ 1.38     $ ( 0.83 ) Loss from discontinued operations, net of tax     —       —       —   Net income (loss) per share   $ 0.74     $ 1.38     $ ( 0.83 ) Basic weighted average shares outstanding     69,568       58,230       57,594   Diluted net income (loss) per share:                         Income (loss) from continuing operations   $ 0.73     $ 1.37     $ ( 0.83 ) Loss from discontinued operations, net of tax     —       —       —   Net income (loss) per share   $ 0.73     $ 1.37     $ ( 0.83 ) Diluted weighted average shares outstanding     69,982       58,755       57,594     See notes to consolidated financial statements   F-4 Table of Contents   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, 2020     67,674       ( 9,649 )   $ 6,767     $ 73,549     $ —     $ ( 41,429 )   $ 70,833     $ 109,720   Shares issued - stock-based compensation     223       ( 44 )     23       40       —       —       —       63   Stock-based compensation expense     —       —       —       848       —       —       —       848   Treasury stock     —       ( 673 )     —       —       —       ( 992 )     —       ( 992 ) Net loss     —       —       —       —       —       —       ( 48,181 )     ( 48,181 ) Balance at December 31, 2020     67,897       ( 10,366 )     6,790       74,437       —       ( 42,421 )     22,652       61,458   Shares issued - stock-based compensation     1,665       ( 573 )     166       1,203       —       —       —       1,369   Stock-based compensation expense     —       —       —       1,060       —       —       —       1,060   Treasury stock     —       —       —       —       —       ( 1,426 )     —       ( 1,426 ) Net income     —       —       —       —       —       —       81,836       81,836   Balance at December 31, 2021     69,562       ( 10,939 )     6,956       76,700       —       ( 43,847 )     104,488       144,297   Shares issued - stock-based compensation     614       —       61       251       —       —       —       312   Stock-based compensation expense     —       —       —       2,105       —       —       —       2,105   Conversion of liability awards to equity     —       —       —       5,336       —       —       —       5,336   Acquisition of TransGlobe     49,307       —       4,931       269,214       —       —       —       274,145   Treasury stock     —       ( 691 )     —       —       —       ( 3,805 )     —       ( 3,805 ) Dividend Distributions     —       —       —       —       —       —       ( 9,354 )     ( 9,354 ) Other comprehensive income     —       —       —       —       1,179       —       —       1,179   Net income     —       —       —       —       —       —       51,890       51,890   Balance at December 31, 2022     119,483       ( 11,630 )   $ 11,948     $ 353,606     $ 1,179     $ ( 47,652 )   $ 147,024     $ 466,105     See notes to consolidated financial statements.   F-5 Table of Contents   VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS     Year Ended December 31,       2022     2021     2020       (in thousands)   CASH FLOWS FROM OPERATING ACTIVITIES:                         Net income (loss)   $ 51,890     $ 81,836     $ ( 48,181 ) Adjustments to reconcile net income (loss) to net cash provided by operating activities:                         Loss from discontinued operations, net of tax     72       98       98   Depreciation, depletion and amortization     48,143       21,060       9,382   Bargain purchase gain     ( 10,819 )     ( 7,651 )     —   Impairment of proved crude oil and natural gas properties     —       —       30,625   Other amortization     —       —       181   Deferred taxes     44,805       ( 39,978 )     24,159   Unrealized foreign exchange (gain) loss     ( 1,043 )     ( 291 )     91   Stock-based compensation     2,200       2,459       114   Cash settlements paid on exercised stock appreciation rights     ( 827 )     ( 3,271 )     ( 275 ) Derivative instruments (gain) loss, net     37,812       22,826       ( 6,577 ) Cash settlements received (paid) on matured derivative contracts, net     ( 42,935 )     ( 18,020 )     7,216   Cash settlements paid on asset retirement obligations     ( 6,577 )     —       —   Bad debt expense and other     3,082       875       1,165   Other operating loss, net     ( 38 )     440       869   Operational expenses associated with equipment and other     2,052       2,415       1,601   Change in operating assets and liabilities:                         Trade receivables     18,385       ( 11,308 )     14,335   Accounts with joint venture owners     ( 18,929 )     1,594       4,016   Other receivables     ( 9,290 )     ( 9,736 )     1,405   Crude oil inventory     ( 1,742 )     5,022       ( 2,834 ) Prepayments and other     ( 4,387 )     1,617       ( 1,126 ) Value added tax and other receivables     ( 5,193 )     ( 1,593 )     ( 1,268 ) Other long-term assets     ( 2,730 )     ( 1,176 )     —   Accounts payable     23,920       ( 922 )     ( 842 ) Foreign income taxes receivable/payable     ( 5,897 )     2,268       ( 4,880 ) Accrued liabilities and other     6,964       1,645       ( 1,383 ) Net cash provided by continuing operating activities     128,918       50,209       27,891   Net cash used in discontinued operating activities     ( 72 )     ( 92 )     ( 441 ) Net cash provided by operating activities     128,846       50,117       27,450   CASH FLOWS FROM INVESTING ACTIVITIES:                         Property and equipment expenditures     ( 159,897 )     ( 16,558 )     ( 20,008 ) Cash acquired from TransGlobe acquisition     36,686       —       —   Acquisition of crude oil and natural gas properties     —       ( 22,505 )     ( 4,320 ) Net cash used in continuing investing activities     ( 123,211 )     ( 39,063 )     ( 24,328 ) Net cash used in discontinued investing activities     —       —       —   Net cash used in investing activities     ( 123,211 )     ( 39,063 )     ( 24,328 ) CASH FLOWS FROM FINANCING ACTIVITIES:                         Proceeds from the issuances of common stock     312       1,369       63   Dividend distribution     ( 9,354 )     —       —   Treasury shares     ( 3,805 )     ( 1,426 )     ( 992 ) Deferred financing costs     ( 2,069 )     —       —   Payments of finance lease     ( 3,039 )     —       —   Net cash used in continuing financing activities     ( 17,955 )     ( 57 )     ( 929 ) Net cash used in discontinued financing activities     —       —       —   Net cash used in financing activities     ( 17,955 )     ( 57 )     ( 929 ) Effects of exchange rate changes on cash     ( 218 )     —       —   NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH     ( 12,538 )     10,997       2,193   CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD     72,314       61,317       59,124   CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD   $ 59,776     $ 72,314     $ 61,317   See notes to consolidated financial statements. F-6 Table of Contents   VAALCO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES       Year Ended December 31,       2022     2021     2020       (in thousands)   Supplemental disclosure of cash flow information:                         Income taxes received in cash   $ —     $ —     $ ( 696 ) Income taxes paid in-kind with crude oil   $ 26,257     $ 20,103     $ 8,738   Interest paid, net of amounts capitalized   $ 1,656     $ —     $ —   Supplemental disclosure of non-cash investing and financing activities:                         Property and equipment additions incurred but not paid at end of period   $ 41,060     $ 15,021     $ 3,966   Non-cash consideration exchanged in the acquisition of TransGlobe   $ 274,145     $ —     $ —   Recognition of right-of-use operating lease assets and liabilities   $ —     $ 581     $ 1,478   Recognition of right-of-use finance lease assets and liabilities   $ 87,166     $ —     $ —   Reclassification of other long-term assets to right-of-use finance lease assets   $ 4,116     $ —     $ —   Liability awards converted to equity   $ 5,336     $ —     $ —   Asset retirement obligations   $ —     $ 21,733     $ 359     See notes to consolidated financial statements.     F-7 Table of Contents   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. As operator, the Company has production operations and conducts exploration activities in Gabon and Canada and hold interests in two production sharing contracts ("PSCs") in Egypt. The Company has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 4 below, VAALCO has discontinued operations associated with activities in Angola, West Africa and Yemen.   On October 13, 2022, the Company and VAALCO Energy Canada ULC (“AcquireCo”), an indirect wholly-owned subsidiary of the Company, completed the previously announced business combination involving TransGlobe Energy Corporation (“TransGlobe”), whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares pursuant to a plan of arrangement (the “Arrangement”) and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO in accordance with the terms of an arrangement agreement entered into by VAALCO, AcquireCo and TransGlobe on July 13, 2022 ( the “Arrangement Agreement”). Prior to the Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in Egypt and Canada. The post-Arrangement company (the “Combined Company”) is an African-focused operator with a diverse portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. See Note 4  for further discussion regarding the Arrangement.   As of December 31, 2022 , the Company’s consolidated subsidiaries were VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited, VAALCO Energy, Inc. (UK Branch), VAALCO Energy (USA), Inc, VAALCO Energy (International), LLC, VAALCO Energy (Holdings), LLC, TransGlobe Energy Corporation, TG Energy UK Ltd, TransGlobe Petroleum International Inc., TG Holdings Yemen Inc., TransGlobe West Bakr Inc., TransGlobe West Gharib Inc., TG Energy Marketing Inc., and TG NW Gharib Inc., TG S Ghazalat Inc.   With respect to the novel strain of COVID- 19,  during  2021,  and continuing in  2022,  crude oil prices have experienced significant improvement and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. However, during the  second  quarter of  2022  the  BA.5  strain of the Omicron variant caused surges in infections worldwide. While COVID- 19  related travel restrictions have gradually eased as governments and people continue to have increasing access to vaccines that help reduce the spread of COVID- 19,  new surges in infections and hospitalizations could alter the current environment. The significant decline in oil prices experienced in  2020  was, in part, due to disruptions in the worldwide economy due to the COVID- 19  pandemic which quarantined people and restricted travel. To date the Company's operations have  not  been materially impacted by COVID- 19,  and worldwide the Company is seeing improving economic activity while managing the risk of a resurgence, but there can be  no  guarantees that COVID- 19  will  not  have an impact on the Company or its operations.   In  July 2021,  the Organization of the Petroleum Exporting Countries, Russia and other allied producing countries (collectively, "OPEC+") agreed to increase production beginning in  August 2021  and to gradually phase out prior production cuts by  September 2022.  However, as a result of the recent decline in oil prices, on  October 5, 2022,  OPEC+ announced plans to reduce overall oil production by  2  MMBbls per day starting  November 2022 through December 2023.  The Company has  not  received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiative.    For the years ended  December 31, 2022 and 2021, crude oil prices have improved, there were no disruptions to operations as a result of COVID- 19 or any strain thereof, global economic activity has steadily increased, and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. Therefore, no additional charges or impairments were required for the year ended December 31, 2022 or 2021. Crude oil prices have stabilized. The average annual Brent price per barrel for the year ended December 31, 2020 was $ 41.96 increasing 69 % to $ 70.86 for  December 31, 2021 and further increasing  42 % to $ 100.93  for the year ended December 31, 2022.    During the year ended December 31, 2022, the Company noticed that the lead times associated with obtaining materials to support its operations and drilling activities have lengthened and, in some cases, prices for fuel and materials have increased. Management believes the ongoing war between Russia and Ukraine and the slowdown of the economy in China and their related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.   F- 8 Table of Contents   While the current commodity price environment is still favorable and the Company has not experienced material disruptions to its operations as a result of COVID- 19 or as result of other forces, including the Russia/Ukraine conflict or slowdown in the Chinese economy, affecting the global market, any emergence of a new variant or further deteriorations of the global supply chain market  may have a material adverse impact on financial results and business operations of the Company, including the timing and ability of the Company to complete future drilling campaigns and other efforts required to advance the development of its crude oil, natural gas and NGLs properties.   NYSE Noncompliance Notice   On April 3, 2023, the Company was notified by the New York Stock Exchange (the “NYSE”) that it was not in compliance with the NYSE’s continued listing requirements under the timely filing criteria established in Section 802.01E of the NYSE Listed Company Manual as a result of its failure to timely file its Annual Report on Form 10 -K for the fiscal year ended December 31, 2022. By filing this report, the Company believes it has remedied its non-compliance.   2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES   Principles of consolidation – The accompanying consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating 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 require extensive 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.   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 time duration. Current amounts in restricted cash at December 31, 2022 and 2021 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at December 31, 2022 and 2021 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note  12. The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the amounts shown in the consolidated statements of cash flows.       As of December 31,       2022     2021       (in thousands)   Cash and cash equivalents   $ 37,205     $ 48,675   Restricted cash - current     222       79   Restricted cash - non-current     1,763       1,752   Abandonment funding     20,586       21,808   Total cash, cash equivalents and restricted cash   $ 59,776     $ 72,314     The Company conducts regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on 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. See Note 11  for further discussion.   F- 9 Table of Contents   On February  28, 2019, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar ("USD") denominated account advised the Company that the bank regulator required transfer of the funds to the Bank Of Central African States (BEAC) which is the Central Bank of the Economic and Monetary Community of Central Africa (CEMAC) of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests since they were working on an abandonment fund common policy for the oil and gas Industry as well as the mining industry. As a result, the Company was  not able to make the annual abandonment funding payment for the years 2019 through 2022 totaling $ 5.8 million, net to VAALCO based on the 2018 abandonment study. On January 12, 2023,  after continued discussions with various BEAC and government officials, the Company was allowed to re-establish a USD denominated account and made whole for the original USD amount of $ 37.3 million that was in the account prior to conversion to a local currency account in 2019. The Company is working with Directorate of Hydrocarbons in Gabon on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.   Accounts with joint venture owners – 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.   Accounts Receivable and Allowance for Doubtful Accounts – The Company’s accounts receivable results from sales of crude oil production, joint interest billings to its joint interest owners for their share of expenses on joint venture projects for which the Company is the operator, and receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company. Portions of the Company’s costs in Gabon (including the Company’s VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). Most of these receivables have payment terms of 30 days or less. The Company monitors the creditworthiness of the counterparties, and it has obtained credit enhancements from some parties in the form of parental guarantees or letters of credit. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements.   The Company routinely assesses the recoverability of all material receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. When collectability is in doubt, the Company records an allowance against the accounts receivable and a corresponding income charge for bad debts, which appears in the “Bad debt expense and other” line item of the consolidated statements of operations and comprehensive income (loss).   As of December 31, 2022 , the outstanding VAT receivable balance in Gabon, excluding the allowance for bad debt, was approximately $ 21.8  million ($ 13.9  million, net to VAALCO). As of  December 31, 2021,  the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $ 14.5  million ($ 9.6  million, net to VAALCO). As of December 31, 2022 , the exchange rate was XAF 612.6  = $1.00. As of December 31, 2021 , the exchange rate was XAF 578.2  = $1.00. 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) income, net” line item of the consolidated statements of operations and comprehensive income (loss).   The following table provides an analysis of the change in the allowance:       Year Ended December 31,       2022     2021     2020       (in thousands)   Allowance for bad debt                         Balance at beginning of period   $ ( 5,741 )   $ ( 2,273 )   $ ( 1,508 ) Bad debt charges, net of receipts     ( 3,082 )     ( 875 )     ( 1,165 ) Adjustment associated with reversal of allowance on Mutamba receivable     —       —       593   Adjustment associated with Sasol Acquisition     —       ( 2,879 )     —   Foreign currency gain (loss)     119       286       ( 193 ) Balance at end of period   $ ( 8,704 )   $ ( 5,741 )   $ ( 2,273 )   F- 10 Table of Contents   Other receivables – Under the terms of the Etame PSC, the Company can be required to contribute to meeting domestic market needs of the Republic of Gabon by delivering to it, or another entity designated by the Republic of Gabon, an amount of crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In 2021, the Company was notified by the Republic of Gabon to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. The Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered. Since the crude-oil produced by the Company was not compatible with the crude-oil requirements of the refinery, the Company entered into two  contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced the compatible oil the refinery needs and another contract with the refinery itself to deliver the crude oil to. Under the contract with the provider of the crude oil, the  third -party provider is entitled to a selling price consistent with the price the Company receives under the terms of the Etame PSC for the delivery of the crude oil to the refinery. As a result of these contracts and timing differences between when the oil is procured and when it is delivered to and paid for by the refinery, included in the Company’s  December 31, 2022  consolidated balance sheet are current receivables in the "Other, net" line item of approximately $ 18.2  million for amounts due to the Company from the refinery for  195  MBbls delivered in September  through  December 2022,  and a $ 17.9  million current liability included in the "Accounts payable" line item for amounts due to the oil supplier for  195  MBbls of crude oil purchased from the supplier in  September  through  December 2022.   On January 19, 2022, TransGlobe’s West Gharib, West Bakr and North West Gharib (collectively the "Eastern Desert") concessions were merged into the Merged Concession Agreement with EGPC. The Merged Concession includes improved cost recovery and production sharing terms scaled to oil prices with a new 15 -year development term and a 5 -year extension option. Upon execution of the Merged Concession, there was an effective date adjustment owed to the Company for the difference between historic and Merged Concession Agreement commercial terms applied against Eastern Desert production from the Merged Concession Effective Date, February 1, 2020. The cumulative amount of the effective date adjustment was estimated at $ 67.5 million. At December 31, 2022, the Company received $ 17.2 million of the receivable and the remaining $ 50.3 million is recorded on the consolidated balance sheet in current receivables in the "Other, net" line item.   Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon, inventories represent the Company's share of crude oil produced and stored on the FSO at December 31, 2022 and the FPSO at December 31, 2021, but unsold at the end of each period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. Crude oil inventory is valued at the lower of cost or net realizable value.    Prepayments and other  – Included in “Prepayments and other” line item of the Company’s December 31, 2022 consolidated balance sheet are $ 4.0 million of prepayments related to fixed assets, $ 4.8 million of prepayments related to royalties in Gabon, $ 2.7  million in prepaid insurance and other, $ 0.9 million in prepaid charter hire for the FSO and $ 7.2 million of prepayment and other assets related to the Company's Canadian and Egyptian operations.    Materials and supplies – Materials and supplies, which are included in the “Prepayments and other” line item of the consolidated balance sheet, are primarily used for production related activities. These assets are valued at the lower of cost, determined by the weighted-average method, or net realizable value.   Crude oil, natural gas and NGLs properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil, natural gas and NGLs producing activities. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by drilling results.   Capitalized Equipment Inventory –   Capitalized equipment inventory represents the costs incurred in bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Capitalized equipment inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle.   F- 11 Table of Contents   Capitalization – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.    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 proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a block basis under the unit-of-production method based upon estimates of 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.   Impairment – The Company reviews the crude oil, natural gas and NGLs producing properties 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 if commodity prices fall below a level that significantly effects anticipated future cash flows. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil, natural gas and NGLs leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon, Canada, Egypt and in Block P in Equatorial Guinea. See Note 9  for further discussion.   Purchase Accounting – On October 13, 2022, the Company and AcquireCo, an indirect wholly-owned subsidiary of the Company, completed the business acquisition of TransGlobe and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement on July 13, 2022. The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 4 for further discussion.   F- 12 Table of Contents   On February  25, 2021, VAALCO Gabon S.A., a wholly owned subsidiary of the Company, completed the acquisition of Sasol Gabon S.A.’s (“Sasol’s”) 27.8 % working interest in the Etame Marin block offshore Gabon pursuant to the sale and purchase agreement (“SPA”) dated November  17, 2020 (the “Sasol Acquisition”). The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 4 for further discussion.   Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. Further, 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. ROU assets for operating leases are recorded under “Right of use operating lease assets” and the current portion and long-term portion of the lease liabilities for operating leases are reflected in “Operating lease liabilities – current portion” and “Operating lease liabilities – net of current portion” within the consolidated balance sheets. ROU assets for financing leases are recorded within “Right of use finance lease assets” and the current portion and long-term portion of the lease liabilities for financing leases are reflected in “Finance lease liabilities – current portion” and “Finance lease liabilities – net of current portion” within the consolidated balance sheets.   Asset retirement obligations ( “ ARO ” ) – The Company has significant 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 is difficult and 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. 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. 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 asset balance or income statement, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil, natural gas and NGLs 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. See Note 11  for further discussion.   Revenue recognition  – The Company's revenues are derived primarily from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers.   Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time and the amounts of revenues recognized relating to performance obligations satisfied over time are not significant. See Note 7 for further discussion.   In connection with the acquisition of TransGlobe on October 13, 2022, the Company has elected to continue its policy regarding shipping and handling costs and are presenting these costs net within revenue in the consolidated statements of operations and comprehensive income (loss). In addition, the Company has elected to recognize revenue from oil, natural gas and NGL’s on the basis of the Company’s net working interest, less royalties the consolidated statements of operations and comprehensive income (loss). Any imbalances from an underlift or overlift position are valued based on the actual sales proceeds received.   F- 13 Table of Contents   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 requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. 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.   Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 17  for further discussion.   Foreign currency transactions – The U.S. dollar is the functional currency of most of the Company’s foreign operating subsidiaries. However, in connection with the Company’s acquisition of TransGlobe, the Company acquired TransGlobe’s Canadian operations whose functional currency is 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). Both realized and unrealized foreign exchange gain and losses are recorded within the consolidated statements of operations and comprehensive income line item “Other (expense) income, net”. The Company recognized losses on foreign currency transactions of $ 4.2  million in 2022, $ 0.7  million in  2021 and a gain on foreign currency transactions of $ 0.2  million in 2020.   Income taxes – The annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil, which is due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.   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.   F- 14 Table of Contents   In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the consolidated financial position and results of operations. See Note 8 for further discussion.   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). See Note 10 for further discussion.   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 represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).   Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).   Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the internally developed present value of future cash flows model that underlies the fair-value measurement).   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, asset retirement assets and liabilities, other long-lived assets and assets acquired and liabilities assumed in a business combination. Generally, a cash flow model is used in combination with inflation rates and credit-adjusted, risk-free discount rates or industry rates to determine the fair value of the assets and liabilities. Based upon review of the fair value hierarchy, the inputs used in these fair value measurements, such as the underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using an average weekly forward strip prices as of the closing date of the acquisition, are considered Level 3 inputs.   Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, accrued liabilities, liabilities for SARs and guarantees. As discussed further in Note 10, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the consolidated balance sheet. SARs liabilities are measured and reported at fair value using level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported in “Accrued liabilities and other” on the consolidated balance sheet while the long-term portion is reported in “Other long-term liabilities”. With respect to cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments and are considered Level 1 inputs. The Company generally extends unsecured credit to these clients; therefore, collection of receivables may be affected by the economy surrounding the oil and natural gas industry or other economic conditions. The Company closely monitors extensions of credit and may negotiate payment terms that mitigate risk.   F- 15 Table of Contents           As of December 31, 2022       Balance Sheet Line   Level 1     Level 2     Level 3     Total           (in thousands)   Assets                                     Derivative asset   Prepayments and other   $ —     $ 102     $ —     $ 102           $ —     $ 102     $ —     $ 102   Liabilities                                     SARs liability   Accrued liabilities and other   $ —     $ 556     $ —     $ 556           $ —     $ 556     $ —     $ 556             As of December 31, 2021       Balance Sheet Line   Level 1     Level 2     Level 3     Total           (in thousands)   Liabilities                                     SARs liability   Accrued liabilities and other   $ —     $ 609     $ —     $ 609   Derivative liability   Accrued liabilities and other     —       4,806       —       4,806           $ —     $ 5,415     $ —     $ 5,415     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. See Note 6 for further discussion.    Other, net – “Other, net” in non-operating income and expenses includes gains and losses from foreign currency transactions as discussed above, as well as taxes other than income taxes.    Other comprehensive income  – All of the Company’s other comprehensive income arises from TransGlobe's Canadian operations whose functional currency is the Canadian dollar. Translation gains and losses occur when translating the financial statements of non-U.S. functional currency operations to the USD. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the consolidated statements of operations and comprehensive income (loss). Translations occur as follows:     • Income and expenses are translated at the date of the transaction   • Assets and liabilities are translated at the prevailing rate on the balance sheet date. On the date of acquisition, October 13, 2022, the exchange rate to convert Canadian dollars (“CAD") to US dollars (“USD”) was 0.724 . At December 31, 2022, the exchange rate was  .0.738  USD.   F- 16 Table of Contents     3. NEW ACCOUNTING STANDARDS   Adopted   In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016 - 13, Financial Instruments – Credit Losses (Topic 326 ): Measurement of Credit Losses on Financial Instruments (“ASU 2016 - 13” ) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. ASU 2016 - 13 is effective for Securities and Exchange Commission filers, excluding smaller reporting companies, for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. As a smaller reporting company, the Company was required to adopt the new standard for the fiscal years beginning after December 15, 2022, including interim periods within those fiscal years.   As of January 1, 2023, the Company adopted the standard, and the adoption of the standard did not have a material impact on its consolidated financial statements.   Not Yet Adopted   In March 2020, the FASB issued ASU 2020 - 04, “Reference Rate Reform (Topic 848 ),” which provides optional expedients and exceptions for applying U.S. GAAP to debt contracts, receivables, leases, derivatives, and other contracts impacted by reference rate reform and other transactions affected by the cessation of the LIBOR. The expiration date of ASU 2020 - 04 was December 31, 2022.   In December 2022, the FASB issued ASU 2022 - 06, “Reference Rate Reform (Topic 848 ): Deferral of the Sunset Date of Topic 848, to extend the expiration date of Topic 848 through December 31, 2024. The expedients, if adopted, can be applied prospectively. As the Company implements alternative rates from LIBOR into our current contracts, it is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.     4. ACQUISITIONS AND DISPOSITIONS   Acquisition of TransGlobe Energy Corporation   On October 13, 2022, the Company and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the issued and outstanding common shares of TransGlobe and TransGlobe became a direct wholly owned subsidiary of AcquireCo and an indirect wholly owned subsidiary of the Company pursuant to an Arrangement agreement entered into by the Company, AcquireCo and TransGlobe on July 13, 2022.   At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement (the “TransGlobe common shares”) was converted into the right to receive 0.6727 (the “exchange ratio”) of a share of VAALCO common stock, par value $ 0.10 per share. The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. The Arrangement resulted in VAALCO stockholders owning approximately 54.5 %, and TransGlobe shareholders owning approximately 45.5 % of the Combined Company, calculated based on vested outstanding shares of each company as of the date of the Arrangement Agreement. The Combined Company results of operations of VAALCO and TransGlobe for the period of October 14, 2022 to December 31,  2022  are included in the Company’s consolidated results for the period ending December 31, 2022.   Prior to the Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in Egypt and Canada. The Combined Company is an African-focused operator with a portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. The transaction qualifies as a business combination under ASC 805, Business Combinations and the Company is the accounting acquiror.   F- 17 Table of Contents   The actual impact of the Arrangement was an increase to “Crude oil, natural gas and NGLs sales” of $ 47.6  million and $ 10.0  million of “ Net income” in the consolidated statements of operations and comprehensive income for the year ended December 31, 2022 .       October 13, 2022       (in thousands)   Purchase Consideration         Common stock issued to TransGlobe shareholders   $ 274,145         October 13, 2022       (in thousands)   Assets acquired:         Cash   $ 36,686   Wells, platforms and other production facilities     243,669   Equipment and other     2,099   Undeveloped acreage     30,216   Accounts receivable - trade     48,068   Accounts receivable - other     50,275   Accounts with joint venture owners     68   Right of use operating leases     1,609   Right of use financing leases     204   Prepayment and other     7,627   Liabilities assumed:         Asset retirement obligations     ( 6,134 ) Accounts payable     ( 10,223 ) Accrued liabilities and other     ( 50,128 ) Operating lease liabilities - current portion     ( 961 ) Financing lease liabilities - current portion     ( 125 ) Operating lease liabilities - net of current portion     ( 688 ) Financing lease liabilities - net of current portion     ( 21 ) Deferred tax liabilities     ( 40,964 ) Other long-term liabilities     ( 26,313 ) Bargain purchase gain     ( 10,819 ) Total purchase price   $ 274,145     F- 18 Table of Contents   All assets and liabilities associated with TransGlobe, including crude oil, natural gas and NGLs properties, asset retirement obligations and working capital items, were recorded at their fair value. The Company used estimated future crude oil prices as of the closing date, October 13, 2022, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using a weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and specific risk adjustment factors based on reserve category discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The purchase price allocation is preliminary pending final determination of the fair values of certain assets and liabilities, primarily the accounts receivable, asset retirement obligations, accounts payable and any contingencies, and any related tax impacts. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed a $ 10.8 million bargain purchase gain was recognized. The bargain purchase gain of $ 10.8 million is included in “Other income (expense), net” in the consolidated statements of operations and comprehensive income (loss). The bargain purchase gain was due to the decrease in the share price of VAALCO stock from the time period when the arrangement agreement was signed, July 13, 2022 and the share price at closing, October 13, 2022 while the exchange ratio, of TransGlobe shares converted to VAALCO shares, remained the same.    For the twelve months ended December 31, 2022,  included in the line item "Other income (expense), net" is $ 14.6  million of transactions costs associated with the Arrangement with TransGlobe.   In connection with the Arrangement with TransGlobe and pursuant to the Arrangement Agreement, at the effective time of the Arrangement, certain awards previously issued to TransGlobe’s key employees and board members who continued their relationship as employees or board members of VAALCO following the Arrangement, continue to be governed by the applicable TransGlobe plan, provided that each such applicable plan has been amended to provide that VAALCO common stock shall be issuable in lieu of TransGlobe common stock with respect to TransGlobe’s deferred share units (“DSU”s), performance share units (“PSU”s) and restricted stock units (“RSU”s), in each case, based on the exchange ratio in the Arrangement. For the PSUs that remained outstanding following the effective time of the Arrangement as described in the immediately preceding sentence, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200 % for PSUs granted in 2020 and 2021; and 64.4 % for PSUs granted in 2022.     On the effective date of the Arrangement, October 13, 2022, the combined fair value of the DSUs, PSU's and RSU's from TransGlobe was $ 6.0 million. On December 16, 2022, the awards were amended from cash-settled liability awards to equity awards. On the date of this conversion, the awards were revalued, based on VAALCO's share price, and the Company recognized a gain of $ 0.6 million in its consolidated statements of operations and comprehensive income. See Note 17, for further information on the DSUs, PSUs and RSUs after the conversion.   Acquisition of Sasol Gabon S.A. ’ s Interest in Etame   On February  25, 2021, VAALCO Gabon S.A. completed the acquisition of Sasol’s 27.8 % working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July  1, 2020. Prior to the Sasol Acquisition, the Company owned and operated a 31.1 % working interest in Etame. The Sasol Acquisition increased the Company’s working interest to 58.8 %. As a result of the Sasol Acquisition, the net portion of production and costs relating to the Company’s Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired in the Sasol Acquisition have been included in VAALCO’s results for periods after February  25, 2021.   The following amounts represent the allocation of the purchase price to the assets acquired and liabilities assumed in the Sasol Acquisition:       February 25, 2021       (in thousands)   Purchase Consideration         Cash   $ 33,959   Fair value of contingent consideration     4,647   Total purchase consideration   $ 38,606     F- 19 Table of Contents       February 25, 2021       (in thousands)   Assets acquired:         Wells, platforms and other production facilities   $ 37,176   Equipment and other     5,568   Value added tax and other receivables     1,234   Abandonment funding     11,781   Accounts receivable - trade     11,220   Other current assets     3,963   Liabilities assumed:         Asset retirement obligations     ( 14,564 ) Accrued liabilities and other     ( 10,121 ) Bargain purchase gain     ( 7,651 ) Total purchase price   $ 38,606     All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil, natural gas and NGLs properties, asset retirement obligations and working capital items, were recorded at their fair value. The Company used estimated future crude oil prices as of the closing date, February 25, 2021, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using the Company’s weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed a $ 7.7 million bargain purchase gain was recognized. A bargain purchase gain of $ 5.2 million is included in “Other income (expense), net” in the consolidated statements of operations and comprehensive income (loss). An income tax benefit of $ 4.1 million, related to the bargain purchase gain, is also included in the consolidated statements of operations and comprehensive income (loss). The bargain purchase gain is primarily attributable to the increase in crude oil price forecasts from the date the SPA was signed, November 17, 2020, to the closing date, February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.   Under the terms of the SPA, a contingent payment of $ 5.0  million was payable to Sasol should the average Dated Brent price over a consecutive 90 -day period from July  1, 2020 to June  30, 2022 exceed $ 60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the contingent payment were met and on April 29, 2021, the Company paid the $ 5.0 million contingent amount to Sasol in accordance with the terms of the SPA.   For the twelve months ended December 31, 2021,  included in the line item "Other income (expense), net" is $ 1.0 million of transaction fees associated with the Sasol Acquisition.    The impact of the Sasol Acquisition was an increase to “Crude oil, natural gas and NGLs sales” of $ 144.8 million and $ 14.6  million of “Net income” in the consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2022.  The impact of the Sasol Acquisition was an increase to “Crude oil, natural gas and NGLs sales” of $ 84.6 million and $ 29.3 million of “Net income” in the consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2021.   The unaudited pro forma results presented below have been prepared to give the effect to the Sasol Acquisition discussed above on the Company’s results of operations for the years ended December 31, 2022 and 2021 , as if the Sasol Acquisition had been consummated on January 1, 2020.  In addition the unaudited pro forma results presented below have been prepared to give the effect to the TransGlobe Arrangement discussed above on the Company’s results of operations for the years ended December 31, 2022 and 2021, as if the Arrangement had been consummated on January 1, 2021. The unaudited pro forma results do not purport to represent what the Company’s actual results of operations would have been if the Sasol Acquisition or TransGlobe Arrangement had been completed on such date or to project the Company’s results of operations for any future date or period.   F- 20 Table of Contents       Year Ended December 31,         2022       2021         (in thousands)     Pro forma (unaudited)                     Crude oil and natural gas sales   $ 547,670   (a)   $ 367,210   (a) Operating income   $ 267,582   (b)   $ 104,924   (c) Net income   $ 130,425   (d)   $ 54,534   (e,f)                       Basic net income per share:                     Income from continuing operations   $ 1.21       $ 0.51     Loss from discontinued operations, net of tax     -         -     Net income per share   $ 1.21       $ 0.51     Basic weighted average shares outstanding     108,206         107,537     Diluted net income per share:                     Income from continuing operations   $ 1.20       $ 0.50     Loss from discontinued operations, net of tax     -         -     Net income per share   $ 1.20       $ 0.50     Diluted weighted average shares outstanding     108,642         108,062       (a) The unaudited pro forma net revenues associated with Crude oil, natural gas and natural gas liquids sales have been adjusted for shipping and handling costs based on the Company’s historical policy and revenue recognition is based on the Company’s working interest, less royalties, the entitlement method. (b) The unaudited pro forma operating income for the year ended December 31, 2022 removes the $ 23.7 million impairment reversal recorded by TransGlobe in 2022, excludes $ 10.2 million of severance costs associated with the Arrangement, excludes $ 6.5 million of TransGlobe transaction costs associated with the Arrangement, reclassifies depreciation expense, for certain leases identified as operating leases, to production expense and adjusts depreciation, depletion and amortization expense related to the depletable assets and asset retirement obligations acquired in the Arrangement based on the purchase price allocation. (c) The unaudited pro forma operating income for the year ended December 31, 2021 removes the $ 31.5 million impairment reversal recorded by TransGlobe in 2021, adjusts costs associated with overlifts to reduce revenue, includes $ 10.2 million of severance costs associated with the Arrangement, reclassifies depreciation expense, for certain leases identified as operating leases, to production expense and adjusts depreciation, depletion and amortization expense related to the depletable assets and asset retirement obligations acquired in the Arrangement based on the purchase price allocation. (d) The unaudited pro forma net income for the year ended December 31, 2022 excludes $ 14.6 million of transaction costs incurred by VAALCO associated with the Arrangement, excludes the bargain purchase gain of $ 10.8 million and reclassifies interest expense, for certain leases identified as operating leases, as production expense. (e) The unaudited pro forma net income for the year ended December 31, 2021 includes $ 21.1 million of transaction costs incurred by VAALCO and TransGlobe associated with the Arrangement, includes the bargain purchase gain of $ 10.8 million and reclassifies interest expense, for certain leases identified as operating leases, as production expense. (f) The unaudited pro forma net income for the year ended December 31, 2021 excludes nonrecurring pro forma adjustments directly attributable to the Sasol Acquisition, consisting of a bargain purchase gain of $ 7.7 million and transaction costs of $ 1.0 million   Discontinued Operations - Angola and Yemen   In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was 40 %, and the Company carried Sonangol P&P, for 10 % of the work program. On September 30, 2016, the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, the Company notified the national concessionaire, Sonangol E.P., that it was withdrawing from the Block 5 PSA and reduced its activities in Angola. As a result of this strategic shift, the Company classified all the related assets and liabilities as those of discontinued operations in the consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in the Company’s consolidated statements of operations and comprehensive income (loss). The Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the year ended December 31, 2022 and 2021 , the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.   As part of the Arrangement with TransGlobe, the Company acquired TG Holdings Yemen Inc. who previously owned TransGlobe's interests in four PSAs in Yemen: Block 32, Block 72, Block 75 and Block S- 1.  In January 2015, TransGlobe relinquished its interests in Block 32 and Block 72 in Yemen (effective dates of March 31, 2015 and February 28, 2015, respectively), and in October 2015 TransGlobe sold its subsidiary that held interests in Block 75 and Block S- 1.  The operating results of the Yemen segment have been classified as discontinued operations for all periods presented in the Company’s consolidated statements of operations and comprehensive income (loss). The Company segregated the cash flows attributable to the Yemen segment from the cash flows from continuing operations for all periods presented in the Company’s consolidated statements of cash flows. During the year ended December 31, 2022, the Yemen segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.   F- 21 Table of Contents     5. SEGMENT INFORMATION   The Company’s operations are based in Gabon, Egypt, 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 evaluates the operation of each geographic segment separately primarily based on Operating income (loss). 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.  No transactions occurred between segments.    Segment activity of continuing operations for the years ended December 31, 2022, 2021 and 2020 and long-lived assets and segment assets at December 31, 2022 and 2021 are as follows:       Year ended December 31, 2022   (in thousands)   Gabon     Egypt     Canada     Equatorial Guinea     Corporate and Other     Total   Revenues:                                                 Crude oil, natural gas and natural gas liquids sales   $ 306,775     $ 37,710     $ 9,841     $ —     $ —     $ 354,326   Operating costs and expenses:                                                 Production expense     96,854       11,936       1,972       1,899       —       112,661   FPSO demobilization     8,867       —       —       —       —       8,867   Exploration expense     258       —       —       —       —       258   Depreciation, depletion and amortization     34,651       10,444       2,921       —       127       48,143   General and administrative expense     3,101       —       —       538       6,438       10,077   Bad debt expense and other     2,743       —       —       339       —       3,082   Total operating costs and expenses     146,474       22,380       4,893       2,776       6,565       183,088   Other operating income, net     38       —       —       —       —       38   Operating income (loss)     160,339       15,330       4,948       ( 2,776 )     ( 6,565 )     171,276   Other income (expense):                                                 Derivative instruments gain (loss), net     —       —       13       —       ( 37,825 )     ( 37,812 ) Interest (expense) income, net     ( 1,446 )     ( 596 )     —       —       8       ( 2,034 ) Other expense, net     ( 1,484 )     —       —       —       ( 6,564 )     ( 8,048 ) Total other Income (expense), net     ( 2,930 )     ( 596 )     13       —       ( 44,381 )     ( 47,894 ) Income (loss) from continuing operations before income taxes     157,409       14,734       4,961       ( 2,776 )     ( 50,946 )     123,382   Income tax (benefit) expense     68,509       6,254       —       1       ( 3,344 )     71,420   Income (loss) from continuing operations     88,900       8,480       4,961       ( 2,777 )     ( 47,602 )     51,962   Loss from discontinued operations, net of tax     —       —       —       —       ( 72 )     ( 72 ) Net income (loss)   $ 88,900     $ 8,480     $ 4,961     $ ( 2,777 )   $ ( 47,674 )   $ 51,890   Consolidated capital expenditures (1)   $ 162,375     $ 168,012     $ 103,263     $ —     $ 710     $ 434,360   ( 1 ) - Includes assets acquired in the TransGlobe acquisition   F- 22 Table of Contents       Year Ended December 31, 2021   (in thousands)   Gabon     Equatorial Guinea     Corporate and Other     Total   Revenues:                                 Crude oil and natural gas sales   $ 199,075     $ —     $ —     $ 199,075   Operating costs and expenses:                                 Production expense     80,717       532       6       81,255   Exploration expense     1,579       —       —       1,579   Depreciation, depletion and amortization     20,972       —       88       21,060   General and administrative expense     1,301       321       13,144       14,766   Bad debt expense and other     875       -       —       875   Total operating costs and expenses     105,444       853       13,238       119,535   Other operating expense, net     ( 440 )     —       —       ( 440 ) Operating income     93,191       ( 853 )     ( 13,238 )     79,100   Other income (expense):                                 Derivative instruments loss, net     —       —       ( 22,826 )     ( 22,826 ) Interest income, net     —       —       10       10   Other (expense) income, net     6,925       ( 3 )     ( 3,428 )     3,494   Total other income (expense), net     6,925       ( 3 )     ( 26,244 )     ( 19,322 ) Income (loss) from continuing operations before income taxes     100,116       ( 856 )     ( 39,482 )     59,778   Income tax (benefit) expense     12,392       1       ( 34,549 )     ( 22,156 ) Income (loss) from continuing operations     87,724       ( 857 )     ( 4,933 )     81,934   Loss from discontinued operations, net of tax     —       —       ( 98 )     ( 98 ) Net income (loss)   $ 87,724     $ ( 857 )   $ ( 5,031 )   $ 81,836   Consolidated capital expenditures (1)   $ 79,169     $ —     $ 52     $ 79,221   ( 1 ) Includes assets acquired in the Sasol acquisition.   F- 23 Table of Contents       Year Ended December 31, 2020   (in thousands)   Gabon     Equatorial Guinea     Corporate and Other     Total   Revenues:                                 Crude oil and natural gas sales   $ 67,176     $ —     $ —     $ 67,176   Operating costs and expenses:                                 Production expense     37,298       1       16       37,315   Exploration expense     3,588       —       —       3,588   Depreciation, depletion and amortization     9,028       —       354       9,382   Impairment of proved crude oil and natural gas properties     30,625       —       —       30,625   General and administrative expense     1,064       430       9,201       10,695   Bad debt expense and other     1,165       —       —       1,165   Total operating costs and expenses     82,768       431       9,571       92,770   Other operating expense, net     ( 1,669 )     —       —       ( 1,669 ) Operating loss     ( 17,261 )     ( 431 )     ( 9,571 )     ( 27,263 ) Other income (expense):                                 Derivative instruments gain, net     —       —       6,577       6,577   Interest income, net     —       —       155       155   Other (expense) income, net     194       3       ( 68 )     129   Total other expense, net     194       3       6,664       6,861   Loss from continuing operations before income taxes     ( 17,067 )     ( 428 )     ( 2,907 )     ( 20,402 ) Income tax expense     16,204       1       11,476       27,681   Loss from continuing operations     ( 33,271 )     ( 429 )     ( 14,383 )     ( 48,083 ) Loss from discontinued operations, net of tax     —       —       ( 98 )     ( 98 ) Net loss   $ ( 33,271 )   $ ( 429 )   $ ( 14,481 )   $ ( 48,181 ) Consolidated capital expenditures   $ 10,503     $ —     $ ( 9 )   $ 10,494     (in thousands)   Gabon     Egypt     Canada     Equatorial Guinea     Corporate and Other     Total   Long-lived assets from continuing operations:                                                 As of December 31, 2022 (1)   $ 213,204     $ 168,012     $ 103,263     $ 10,000     $ 793     $ 495,272   As of December 31, 2021 (2)     84,156     $ —     $ —     $ 10,000     $ 168     $ 94,324   ( 1 ) - Includes assets acquired in the TransGlobe acquisition ( 2 ) - Includes assets acquired in the Sasol acquisition   (in thousands)   Gabon     Egypt     Canada     Equatorial Guinea     Corporate and Other     Total   Total assets from continuing operations:                                                 As of December 31, 2022 (1)   $ 395,393     $ 293,640     $ 110,071     $ 10,861     $ 45,676     $ 855,641   As of December 31, 2021 (2)     201,748     $ —     $ —     $ 10,548     $ 50,794     $ 263,090   ( 1 ) - Includes assets acquired in the TransGlobe acquisition ( 2 ) - Includes assets acquired in the Sasol acquisition   F- 24 Table of Contents   Information about the Company ’ s most significant customers   The Company currently sells crude oil production from Gabon under term crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs") with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.    As discussed further in Note 13, on May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”) entered into a facility agreement (the “Facility Agreement”) by and among the Company, VAALCO Gabon, SA (“VAALCO Gabon”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an initial aggregate maximum principal amount available of up to $ 50.0 million. In connection with the entry into the Facility Agreement, the Company entered into a COSMA with Glencore pursuant to which the Company agreed to make Glencore the exclusive offtaker and marketer of all of the crude oil produced from the Etame G4 - 160 Block, offshore Gabon during the period from August 1, 2022 until the final maturity date of the Facility (as defined in the Facility Agreement) which is May 15, 2027  unless early terminated. Pursuant to the COSMA, Glencore agreed to buy and market the Company’s crude oil with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.   From February 2019 through  January 2020, crude oil sales were to Mercuria Energy Trading SA (“Mercuria”). The Company entered an COSPA and amendments with ExxonMobil that covered sales from February 2020 through July  2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.    For the year ended December 31, 2022, Etame revenues from the sales of crude oil to Exxon made up 68 % of revenues and sales of crude oil to Glencore made up 32 % of revenues. For the period of October 14, 2022 through December 31, 2022,  EGPC covered 100 % of the Company’s crude oil sales in Egypt. For the period of October 14, 2022 through December 31, 2022, revenues in Canada were concentrated in three separate customers that constituted approximately 54 %, 32 % and 14 % of revenues. Concentrations of accounts receivable are similar to the revenue percentages.      6. EARNINGS PER SHARE   Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.   F- 25 Table of Contents   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,       2022     2021     2020       (in thousands)   Net income (loss) (numerator):                         Income (loss) from continuing operations   $ 51,962     $ 81,934     $ ( 48,083 ) Income from continuing operations attributable to unvested shares     ( 594 )     ( 1,336 )     —   Numerator for basic     51,368       80,598       ( 48,083 ) Loss from continuing operations attributable to unvested shares     3       —       —   Numerator for dilutive   $ 51,371     $ 80,598     $ ( 48,083 )                           Loss from discontinued operations, net of tax   $ ( 72 )   $ ( 98 )   $ ( 98 ) Loss from discontinued operations attributable to unvested shares     1       2       —   Numerator for basic     ( 71 )     ( 96 )     ( 98 ) (Income) loss from discontinued operations attributable to unvested shares     —       —       —   Numerator for dilutive   $ ( 71 )   $ ( 96 )   $ ( 98 )                           Net income (loss)   $ 51,890     $ 81,836     $ ( 48,181 ) Net income attributable to unvested shares     ( 593 )     ( 1,334 )     —   Numerator for basic     51,297       80,502       ( 48,181 ) Net (income) loss attributable to unvested shares     3       —       —   Numerator for dilutive   $ 51,300     $ 80,502     $ ( 48,181 )                           Weighted average shares (denominator):                         Basic weighted average shares outstanding     69,568       58,230       57,594   Effect of dilutive securities     414       525       —   Diluted weighted average shares outstanding     69,982       58,755       57,594   Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive     189       169       3,545       7. REVENUE   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"). COSPAs and COSMAs with customers are renegotiated near the end of the contract term and may be entered into with a different customer or the same customer going forward. Except for internal costs, which are expensed as incurred, there are no upfront costs associated with obtaining a new COSPA or COSMA. See Note 5 under “ Information about the Company ’ s most significant customers ” for further discussion.   Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO or FSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The intervals between liftings are generally one month; however, changes in the timing of liftings will impact the number of liftings that occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations. 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.    F- 26 Table of Contents   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. However, under the COSMA, each coventurer is responsible for invoicing Glencore their respective ownership interest in the final volumes.   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.   Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, the Company deemed this situation to be characterized as a fixed price situation.   In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. The Etame PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. 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. Should the government elect to take the production attributable to its royalty in-kind, the Company would no longer have sales to customers associated with production assigned to royalties.   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. Prior to February  1, 2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February  1, 2018, these sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, 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, i.e. the period in which it lifts the crude oil. An in-kind payment of $ 26.3 million was made with the December 2022  lifting. With this lifting, the government lifted more oil in-kind than what was owed to it in foreign taxes. Therefore, the Company has a $ 2.8  million foreign income tax receivable as of December 31, 2022 . As of December 31, 2021 , the foreign income taxes payable attributable to this obligation was $ 3.1  million.   Certain amounts associated with the carried interest in the Etame Marin block discussed above 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,       2022     2021     2020   Revenues from customer contracts:   (in thousands)   Sales under the COSPA or COSMA   $ 320,522     $ 200,321     $ 67,041   Other items reported in revenue not associated with customer contracts:                         Gabonese government share of Profit Oil taken in-kind     26,257       20,103       8,738   Carried interest recoupment     5,843       7,517       1,631   Royalties     ( 45,847 )     ( 28,866 )     ( 10,234 ) Crude oil and natural gas sales   $ 306,775     $ 199,075     $ 67,176     F- 27 Table of Contents   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’s subsidiary, TransGlobe Petroleum International (“TPI”), each own a 50 % interest, respectively, in the operating company which is a party to the Merged Concession Agreement. EGPC and the Company’s subsidiary, TPI, each also own a 50 % interest, respectively, in the operating company that is a party to the South Ghazalat concession agreement. 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.   Customer sales generally occur on a daily basis when sales are directly to EGPC or haphazardly production is sold through a cargo lifting. Direct sales to EGPC are considered complete when oil is delivered to EGPC storage facility. When sales are made through cargo lifting, the performance obligations are normally satisfied either when the oil is delivered to the export facility location or when the oil is delivered to its ultimate destination, as specified in the contract. Regardless of the type of sales, there is a single performance obligation (delivering crude oil to the delivery point) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.    Revenues associated with the sales of the Company’s crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, 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. For reporting purposes, 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 which is discussed below.    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 Company'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. Typically the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more profit-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. EGPC’s share of productionwill increase during times of rising oil prices and decrease in times of declining oil prices. If oil prices are sufficiently low and the Gharib Blend/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSCs and any eligible extension periods.    With respect to Egyptian income taxes, which are the Company’s liability under the terms of the Merged Concession Agreement, these taxes are paid by EGPC on behalf of the Company out of EGPC’s share of production entitlement. The income taxes paid to the Arab Republic of Egypt on behalf of the Company are recognized as crude oil revenue and income tax expense for reporting purposes.   EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings occur, the Company has a 30 -day collection cycle on liftings as a result of direct marketing to international purchasers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Direct sales to EGPC are normally settled two to four weeks from delivery.    In some instances TPI will borrow or loan production volumes in order to achieve a required amount of crude oil for cargo sales. In these instances TPI can be in an overlift or underlift position. Regardless of being in an over lift or underlift position, sales are based on the Company’s working interest, less royalties. Imbalances are valued based on the actual sales proceeds and TPI 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.   F- 28 Table of Contents   The following table presents revenues in Egypt from contracts with customers:       October 14 - December 31, 2022                 Sales   Revenues from customer contracts:   (in thousands)   Gross sales   $ 56,452   Royalties     ( 18,742 ) Net revenues   $ 37,710     Canada   Revenues from the sale of crude oil, natural gas, condensate and natural gas liquids ("NGLs") in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. 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. Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are measured at the transaction price that the Company expects to be entitled in exchange for transferring promised goods to a customer and is determined based at the fair value of the consideration received. VAALCO pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime. For reporting purposes, the Company records revenues net of royalties.   Customer sales generally occur on a daily basis when crude oil, natural gas, condensate or NGL’s are sold, normally via pipeline, to a delivery point. Regardless of the type of sales, 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. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses.    Settlement of accounts receivable in Canada occur on the 25th of the following month after production.    The following table presents revenues in Canada from contracts with customers:     October 14 - December 31, 2022                 Sales   Revenues from customer contracts:   (in thousands)   Oil revenue   $ 7,362   Gas revenue     1,340   NGL revenue     2,235   Condensate revenue     7   Other revenue     34   Royalties     ( 1,137 ) Net revenues   $ 9,841     F- 29 Table of Contents     8. INCOME TAXES   VAALCO and its domestic subsidiaries file a consolidated U.S. income tax return. Certain foreign subsidiaries also file tax returns in their respective local jurisdictions that include Canada, Egypt, Equatorial Guinea and Gabon.   Income taxes attributable to continuing operations for the year ended December 31, 2022 are attributable to foreign taxes payable in Gabon and Egypt whereas for the years ended December 31, 2021 and 2020 the income taxes are attributable to foreign taxes payable in Gabon as well as income taxes in the U.S.    Provision for income taxes related to income (loss) from continuing operations consists of the following:       Year Ended December 31,       2022     2021     2020       (in thousands)   U.S. Federal:                         Current   $ —     $ —     $ ( 337 ) Deferred     ( 3,344 )     ( 34,548 )     11,814   Foreign:                         Current     26,615       20,282       3,859   Deferred     48,149       ( 7,890 )     12,345   Total   $ 71,420     $ ( 22,156 )   $ 27,681     As of December 31, 2022 the Company had total deferred tax assets of $ 99.6  million primarily attributable to Canada, Gabon and the U.S. whereas for December 31, 2021 deferred tax assets were $ 86.9  million primarily attributable to Gabon and U.S. In both years, the income taxes related to basis differences in fixed assets, foreign tax credit carryforwards, as well as U.S. and foreign net operating loss carryforwards. In assessing the realizability of the deferred tax assets, the Company considers all available positive and negative evidence by jurisdiction and makes a determination whether it is more likely than not that some or all of the deferred tax assets will be realized. 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.   As of December 31, 2022, due to a positive outlook regarding future taxable income, the Company determined that it is more likely than not that it would be able to utilize a large portion of its U.S deferred tax assets. Additionally, the Company also determined that it is more likely than not that it would not be able to utilize its deferred tax assets in Canada and in Egypt for its South Ghazalat concession. As of December 31, 2021, the Company determined that it is more likely than not that it would not be able to utilize its deferred tax assets. On the basis of these evaluations, a valuation allowance of $ 47.6 million and $ 46.9  million were recorded as of December 31, 2022 and 2021, respectively. Valuation allowances reduce the deferred tax assets to the amount that is more likely than not to be realized.     F- 30 Table of Contents   The primary differences between the financial statement and tax bases of assets and liabilities resulted in deferred tax assets associated with continuing operations at December 31, 2022 and 2021 are as follows:       As of December 31,   (in thousands)   2022     2021   Deferred tax assets:                 Basis difference in fixed assets   $ 9,299     $ 20,133   Foreign tax credit carryforward     14,848       20,084   Net operating losses     48,981       25,182   Foreign deferred tax assets, net of impact on U.S. taxes     —       8,693   Asset retirement obligations     8,531       8,546   Operating lease liabilities     10,753       1,750   Basis difference in accrued liabilities     3,800       402   Basis difference in receivables     2,783       454   Other     622       1,683   Total deferred tax assets     99,617       86,927   Valuation allowance     ( 47,583 )     ( 46,949 ) Net deferred tax assets   $ 52,034     $ 39,978                     Deferred tax liabilities:                 Basis difference in fixed assets     ( 97,825 )     —   Net deferred tax liabilities   $ ( 97,825 )   $ —     Foreign net operating losses (“NOLs”) are subject to varying expiration periods depending on the jurisdiction. The NOLs for the Gabon subsidiaries are included in the respective subsidiaries’ cost oil accounts, which will be offset against future taxable revenues and do not expire. U.S. federal NOLs incurred after 2017 do not expire. The ability to utilize NOLs and other tax attributes could be subject to a limitation if the Company were to undergo an ownership change as defined in Section 382 of the Tax Code. Foreign tax credits will expire between the years 2024 and 2032. The Company does not anticipate utilization of the foreign tax credits prior to expiration and has recorded a full valuation allowance on these deferred tax assets.   The Company has NOL’s,  (in '000s )  in the following jurisdictions as of December 31, 2022: Jurisdiction   Amount     Expiration Period   U.S.   $ 45,498     No expiration   Gabon   $ 37,983     No expiration   Egypt   $ 14,558       2023 - 2027   Canada   $ 130,542       2024 - 2042     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, 2022 and 2021 . The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense.   F- 31 Table of Contents   Income (loss) from continuing operations before income taxes is attributable as follows:     Year Ended December 31,   (in thousands)   2022     2021     2020   U.S.   $ ( 56,750 )   $ ( 38,867 )   $ ( 2,908 ) Foreign     180,132       98,645       ( 17,494 )     $ 123,382     $ 59,778     $ ( 20,402 )   The reconciliation of income tax expense (benefit) attributable to income (loss) from continuing operations to income tax on income (loss) from continuing operations at the U.S. statutory rate is as follows:     Year Ended December 31,   (in thousands)   2022     2021     2020   Tax provision computed at U.S. statutory rate   $ 25,910     $ 12,553     $ ( 4,284 ) Foreign taxes not offset in U.S. by foreign tax credits     53,851       35,306       ( 9,801 ) Permanent differences     778       ( 703 )     97   Foreign tax credit expirations     17,247       14,060       —   Increase/(decrease) in valuation allowance     ( 25,623 )     ( 83,372 )     41,635   Other     ( 743 )     —       34   Total income tax expense (benefit)   $ 71,420     $ ( 22,156 )   $ 27,681     For the years ended December 31, 2022, 2021 and 2020 , the Company is subject to foreign and U.S. federal taxes only, with no allocations made to state and local taxes. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions.   Jurisdiction   Years   U.S.   2014 - 2022   Gabon   2018 - 2022   Egypt   2017 - 2022   Canada   2018 - 2022     With respect to the earnings of VAALCO's Canadian foreign subsidiary, the Company does not intend to repatriate funds and will indefinitely reinvest these foreign earnings. Determining the amount of the unrecorded deferred tax liability related to temporary differences at this time is not practicable. If circumstances change and it becomes apparent that some or all the undistributed earnings of our Canadian subsidiary will be remitted in the foreseeable future, the Company shall accrue as an expense of the current period income taxes attributable to that remittance.   With respect to the earnings of VAALCO's Egyptian foreign subsidiaries, the earnings are available for repatriation, but the corresponding incremental tax expense on any remittances is not expected to be material.     On August 16, 2022, legislation commonly known as the Inflation Reduction Act was signed into law. Among other things, the Inflation Reduction Act includes a 1% excise tax on corporate stock repurchases (applicable to repurchases after December 31, 2022) as well as a new minimum tax based on book income. While the Inflation Reduction Act did not have a material impact on its effective tax rate in 2022, the analysis of the impact of the Inflation Reduction Act on the Company is ongoing.   9. CRUDE OIL, NATURAL GAS and NGLs PROPERTIES AND EQUIPMENT   The Company’s crude oil, natural gas and NGLs properties and equipment is comprised of the following:       As of December 31, 2022     As of December 31, 2021       (in thousands)   Crude oil and natural gas properties and equipment - successful efforts method:                 Wells, platforms and other production facilities   $ 1,406,888     $ 488,756   Work-in-progress     —       13,515   Undeveloped acreage     56,251       23,735   Equipment and other     38,796       23,478         1,501,935       549,484   Accumulated depreciation, depletion, amortization and impairment     ( 1,006,663 )     ( 455,160 ) Net crude oil and natural gas properties, equipment and other   $ 495,272     $ 94,324     F- 32 Table of Contents   Extension of Term of Etame Marin Block PSC   On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Etame Consortium”), received an implementing Presidential Decree from the government of Gabon authorizing the PSC Extension to the Etame Consortium to operate in the Etame Marin block. The Company’s subsidiary, VAALCO Gabon S.A., currently has a 63.575 % participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.   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. Prior to the PSC Extension, the exploitation periods for the three exploitation areas in the Etame Marin block would expire beginning in June 2021. The PSC Extension also grants the Etame Consortium the right for two additional extension periods of five years each. The PSC Extension further allows the Etame Consortium to explore the potential for resources within the area of each Exclusive Exploitation Authorization as defined in the PSC Extension.   In consideration for the PSC Extension, the Etame Consortium agreed to a signing bonus of $ 65.0  million ($ 21.8  million, net to VAALCO) payable to the government of Gabon (the “signing bonus”). The Etame Consortium paid $ 35.0  million ($ 11.8  million, net to VAALCO) in cash on September  26, 2018 and paid $ 25.0  million ($ 8.4  million, net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the Etame Consortium as of the effective date. An additional $ 5.0  million ($ 1.7  million, net to VAALCO) was paid in cash by the Etame Consortium following the end of the drilling activities described below.   As required under the PSC Extension, the Etame Consortium completed drilling two development wells and two appraisal wellbores during the 2019/2020 drilling campaign with the last appraisal wellbore completed in February 2020. During September 2020, the Etame Consortium completed the two technical studies at a cost of $ 1.5 million gross ($ 0.5 million, net to VAALCO).   In accordance with the Etame Marin block PSC, the Etame Consortium maintains a “Cost Account,” which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. Under the PSC Extension, the Cost Recovery Percentage 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 %. The government of Gabon will acquire from the Etame Consortium an additional 2.5 % gross working interest carried by the Etame Consortium effective June 20, 2026. VAALCO’s share of this interest to be transferred to the government of Gabon is 1.6 %.   Proved Properties The Company reviews the crude oil, natural gas and NGLs producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil, natural gas and NGLs property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.   F- 33 Table of Contents   There was no triggering event in the year ended December 31, 2022 that would cause the Company to believe the value of crude oil, natural gas and NGLs producing properties should be impaired. Factors considered included higher forward price curves for the fourth quarter of 2022  and capital expenditures in the period related to its reserves in Gabon, Egypt and Canada.   Declining forecasted oil prices in the first quarter of 2020 caused the Company to perform an impairment review during this period. The impairment test was performed using the year end 2019 independently prepared reserve report, estimated reserves for the South East Etame 4H well completed in March 2020 and forward price curves. The Company performed a recoverability test as defined under ASC 932 and ASC 360, noting that the undiscounted cash flows related to the Etame Marin block were less than the book value for the block, resulting in the Company recording a $ 30.6 million impairment loss to write down the Company’s investment to its fair value of $ 15.6 million.   Undeveloped Leasehold Costs   VAALCO acquired a 31 % working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The Ministry of Mines and Hydrocarbons (“EG MMH”) approved the Company's appointment as the operator of Block P on November 12, 2019. The Company acquired an additional working interest of 12 % from Atlas Petroleum, thereby increasing its working interest to 43 % in 2020, in exchange for a potential future payment of $ 3.1 million to Compania Nacional de Petroles de Guinea Equitoria, (“GEPetrol”) in the event that there is commercial production from Block P. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. In April 2021, Crown Energy, who held a 5 % working interest elected to default on its obligations of Block P. On April 12, 2021, the non-defaulting parties assigned the defaulting party’s interest to the non-defaulting parties as required by the Joint Operating Agreement. As a result, VAALCO’s working interest increased to 45.9 % when the EG MMH approved the fourth amendment to the production sharing contract. As of December 31, 2022 , the Company had $ 10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. The Company has completed a feasibility study of a standalone development concept of the Venus discovery on Block P. On September 26, 2022, the EG MMH approved the submitted plan of development. Final documents to effect the plan of development are subject to EG MMH approval. The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and was approved effective November 16, 2022. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan for the area associated with the Venus development. As of December 31, 2022, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license.   In February of 2023, the Company acquired an additional 14.1 % participating interest, increasing VAALCO’s participating interest in the Block to 60.0 %. In March 2023, Atlas voted to participate in the Venus Development. Amendment 5 of the PSC was approved by all parties in March  2023  with this updated participating interest, and execution of the Venus development plan has been initiated. This increase of 14.1% participating interest increases the Company's future payment to GEPetrol to $ 6.8  million at first commercial production of the Block.   As a result of the PSC Extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $ 6.7 million of the share of the signing bonus and $ 7.1 million of the $ 18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame Marin block PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, $ 2.3 million of costs were transferred to proved leasehold costs leaving a remaining $ 11.5 million in unproved leasehold costs. In connection with the Sasol Acquisition discussed under Note 4, $ 2.2 million of reserves were attributed to undeveloped properties. The balance of undeveloped leasehold costs related to the Etame Marin block at December 31, 2021 was $ 13.7 million.   In connection with the TransGlobe acquisition discussed under Note 4, $ 30.2  million of reserves were attributed to undeveloped properties and leasehold costs.    Capitalized Equipment Inventory   Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded in the “Other operating income (expense), net” line item of the consolidated statements of operations and comprehensive income (loss). During the years ended December  31, 2022, 2021 and 2020, adjustments for inventory obsolescence were not material.   F- 34 Table of Contents     10. DERIVATIVES AND FAIR VALUE   The Company uses derivative financial instruments from time to time to achieve a more predictable cash flow from crude oil production by reducing the exposure to price fluctuations. See Note 2 for further information.   Commodity swaps     On January  22, 2021, the Company entered into commodity swaps at a Dated Brent weighted average of $ 53.10 per barrel for the period from and including February 2021 through January 2022 for a quantity of 709,262 barrels. On May  6, 2021, the Company entered into commodity swaps at a Dated Brent weighted average price of $ 66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August  6, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $ 67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $ 72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels. See the table below for the unexpired swaps as of December 31, 2022 .   On October 26, 2022, the Company entered into additional derivatives contracts for the first quarter of 2023.  The details are in the chart below:   Settlement Period   Type of Contract   Index   Average Monthly Volumes     Weighted Average Put Price     Weighted Average Call Price               (Bbls)     (per Bbl)     (per Bbl)   January 2023 to March 2023   Collars   Dated Brent     101,000     $ 65.00     $ 120.00     While these derivative instruments are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, the Company has not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. The Company does not enter into derivative instruments for speculative or trading proposes. In connection with the RBL facility entered in May 2022, the Company is required to hedge a portion of its anticipated oil production at the time the Company draws down on the borrowing base.   The derivative instruments are measured at fair value using the Income Method. Level 2 observable inputs used in the valuation model include market information as of the reporting date, such as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates. The determination of the derivative instrument contracts’ fair value includes the impact of the counterparty’s non-performance risk.   To mitigate counterparty risk, the Company enters into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.   At times, the Company’s counterparties require that it post collateral for changes in the net fair value of the derivative contracts. This cash collateral is reported in the line item "Restricted cash" on the condensed consolidated balance sheets.   F- 35 Table of Contents   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   Statement of Operations Line   2022     2021     2020           (in thousands)   Commodity derivatives   Cash settlements paid on matured derivative contracts, net   $ ( 42,935 )   $ ( 18,020 )   $ 7,216       Unrealized gain (loss)     5,123       ( 4,806 )     ( 639 )     Derivative instruments gain (loss), net   $ ( 37,812 )   $ ( 22,826 )   $ 6,577     Subsequent Event   The Company entered into additional derivative contracts for the second and third quarters of 2023.  The details are in the chart below:   Settlement Period Type of Contract Index   Average Monthly Volumes     Weighted Average Put Price     Weighted Average Call Price           (Bbls)     (per Bbl)     (per Bbl)   April 2023 to June 2023 Collars Dated Brent     95,500     $ 65.00     $ 100.00   July 2023 to September 2023 Collars Dated Brent     95,500     $ 65.00     $ 96.00       11. ASSET RETIREMENT OBLIGATIONS   The following table summarizes the changes in the Company’s asset retirement obligations ("ARO's"):   (in thousands)   As of December 31, 2022     As of December 31, 2021   Beginning balance   $ 40,694     $ 17,334   Accretion     1,958       1,627   Additions     6,134       14,564   Revisions     ( 43 )     7,169   Settlements     ( 6,577 )     —   Foreign currency gain (loss)     ( 165 )       Ending balance   $ 42,001     $ 40,694     Accretion is recorded in the line item “Depreciation, depletion and amortization” on the consolidated statements of operations and comprehensive income (loss).   In connection with the TransGlobe Arrangement in October 2022, as discussed in Note 4, the Company added $6.1  million of ARO for the future abandonment and reclamation costs of the Canadian assets. The Egypt concessions have no ARO.    The Company provides for asset retirement obligations on all of its Canadian operations based on current legislation and industry operating practices. The estimated present value of the asset retirement obligation is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The estimated ARO liability for Canada includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as using inflation factors and discount rates in order to calculate the amount of the ARO liability.   In Egypt, under model concession agreements and the Fuel Material Law, liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process. While the current risk to the Company of becoming liable for decommissioning liabilities in Egypt is low, future changes to legislation could result in decommissioning liabilities in Egypt. Any increase in Egyptian decommissioning liabilities could adversely affect the Company's financial condition.   F- 36 Table of Contents   In relation to petroleum wells, under good oilfield practices, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC during the life of the concession agreement. If EGPC agrees that a producing well is not economic, then the contractor may be responsible for decommissioning the well under an EGPC approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. As EGPC has discretion on decommissioning wells, there is a risk that the Company could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism. At December 31, 2022,  no asset retirement obligation is recorded associated with the Egypt PSCs.   With relation to the end of the FPSO contract in October 2022, the Company incurred decommissioning settlement fees totaling $ 6.6 million previously recorded in the asset retirement obligations and included on the consolidated statements of cash flows in the line item, "Cash settlements paid on asset retirement obligations".   In connection with the Sasol Acquisition in February 2021, as discussed in Note 4, the Company added $ 14.6 million of asset retirement obligations as a result of increasing its interest in the Etame Marin block in Gabon.   The Company is required under the Etame PSC for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was prepared in November 2021. At December 31, 2021, associated with the study, the Company recorded an upward revision of $ 7.2 million to the asset retirement obligation primarily as a result of increased costs expected with the abandonment of the Etame Marin block and a change in the expected timing of the abandonment costs associated with the termination of the FPSO charter, as discussed further in Note 12. As a result of the expected timing of the abandonment of the FPSO, included in accrued liabilities in the consolidated balance sheet at  December 31, 2022  and  December 31, 2021 is $ 0.3 and $ 6.7 million of costs, respectively, associated with the retirement obligation associated with the FPSO.     12. COMMITMENTS AND CONTINGENCIES   Abandonment funding   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 periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, a new abandonment study was done and the estimate used for this purpose is approximately $ 81.3  million ($ 47.8  million, net to VAALCO) on an undiscounted basis. The new abandonment estimate has been presented to the Gabonese Directorate of Hydrocarbons as required by the PSC. Through December 31, 2022 , $ 35.0  million ($ 20.6  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.   On February  28, 2019, in accordance with certain foreign currency regulatory requirements, the Gabonese branch of an international commercial bank holding the abandonment funds in a USD denominated account transferred the funds to the Central Bank for CEMAC, of which Gabon is one of the six member states. The USDs were converted to local currency with a credit back to the Gabonese branch. The Etame PSC provides these payments must be denominated in USD and the CEMAC regulations provide for establishment of a USD account with the Central Bank. During the year ended December 31, 2022, the Company has recorded a $ 1.2  million foreign currency loss associated with the abandonment funding account. During the year ended December 31, 2021, the Company has recorded a $ 1.6  million foreign currency loss associated with the abandonment funding account. After continued discussions with CEMAC, they agreed to the return of the USD funds and on January 12, 2023, the abandonment funds were returned to the USD account of the Gabonese branch of the international commercial bank. The Company was allowed to re-establish a USD denominated account and made whole for the original USD amount of $37.3 million that was in the account prior to conversion to a local currency account in 2019. The Company is working with Directorate of Hydrocarbons in Gabon on establishing a payment schedule to resume funding of the abandonment fund in compliance with the Etame PSC.   F- 37 Table of Contents   FPSO charter   In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for two one -year periods beyond September 2020. These elections have been made, and the charter has been extended through September 2022. On September 9, 2022, the Company signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022 and ratified certain decommissioning and demobilization items associated with exiting the contract.   Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $ 150,000 from August 20, 2022 through October 4, 2022, and other demobilization fees totaling $ 15.3 million on a gross basis, $ 8.9 million net to VAALCO Gabon. The Company obtained guarantees from each of the Company’s joint venture owners for their respective shares of the payments. The Company’s net share of the charter payment is 58.8 %, or approximately $ 19.4  million per year. The Company recorded a liability of $ 0.4 million as of December 31, 2021, representing the guarantee’s estimated fair value. The Company relinquished control over the FPSO in the fourth quarter of 2022.  In connection with the addendum, the FPSO was decommissioned. VAALCO and the owners of the FPSO are performing a settlement of final accounting and will afterwards conclude on the restricted cash balances associated with the FPSO.   The FPSO charter payment included a $ 1.16  per barrel charter fee for production up to 20,000 barrels of crude oil per day and a $ 3.13  per barrel charter fee for those barrels produced in excess of 20,000 barrels of crude oil per day. VAALCO’s net share of these payments was $ 22.4  million, $ 22.1  million and $ 13.1  million for the years ended December 31, 2022, 2021 and 2020 , respectively.   Regulatory and Joint Interest Audits and Related Matters   The Company is subject to periodic routine audits by various government agencies in Gabon, including audits of the Company’s petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under the Company’s joint operating agreements.   In 2016, the government of Gabon conducted an audit of the Company’s operations in Gabon, covering the years 2013 through 2014. The Company received the findings from this audit and responded to the audit findings in January 2017. Since providing the Company’s response, there have been changes in the Gabonese officials responsible for the audit. The Company is working with the newly appointed representatives to resolve the audit findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.   Between 2019 and 2021, the government of Gabon conducted an audit of the operations in Gabon, covering the years 2015 and 2016.  The Company received the findings from this audit and responded to the audit findings in the first quarter of 2023 and are working with the government of Gabon on the results of the findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.   In 2019, the Etame joint venture owners conducted audits for the years 2017 and 2018. In June 2020, the Company agreed to a $ 0.8 million payment to resolve claims made by one of the Etame Marin block joint venture owners, Addax Petroleum Gabon S.A. There are now no unresolved matters related to the joint venture owner audits for these years.   FSO   On August 31, 2021, the Company and its co-venturers at Etame approved the Bareboat Contract (the “Bareboat Contract”) and Operating Agreement (collectively, the “FSO Agreements”) with World Carrier Offshore Services Corp. to replace the existing FPSO with a Floating Storage and Offloading unit (“FSO”). The FSO Agreements required a prepayment of $ 2 million gross, $ 1.2  million net to the Company, in 2021 and $ 5 million gross, $ 3.2 million net to the Company, in 2022 of which $ 6 million will be recovered against future rentals. Total field conversion expenses were $ 122 million gross ($ 77 million net to VAALCO). The FSO Agreements contain purchase provisions and termination provisions. On October 19, 2022, the vessel is on location at the Etame Marin block and the Company has issued its final acceptance certificate of the FSO.   F- 38 Table of Contents   Dividend Policy   On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend policy of an expected $ 0.0325 per common share commencing in the first quarter of 2022. The following table is a schedule of dividends paid during 2022: Dividend Payment Date   Amount per common share   Record Date March 18, 2022   $ 0.0325   February 18, 2022 June 24, 2022   $ 0.0325   May 25, 2022 September 23, 2022   $ 0.0325   August 25, 2022 December 22, 2022   $ 0.0325   November 22, 2022 Aggregate per share amount paid in 2022   $ 0.1300       In the first quarter of 2023, the Company announced that the Company's board of directors increased the cash dividend to $ 0.0625 per common share. On February 14, 2023 , our board of directors declared a quarterly cash dividend of $ 0.0625  per common share, which was payable on March 31, 2023 to stockholders of record at the close of business on March 24, 2023.   In connection with the RBL facility, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, the Company  may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the year ended December 31, 2022, no specific approval or waivers were required for the Company to make distributions or repurchase stock.    Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.   Share Buyback Program   On November 1, 2022, the Company announced that the Company’s board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with the Company’s business combination with TransGlobe. The board of directors also directed management to implement a Rule 10b5 - 1 trading plan (the “10b5 - 1 Plan”) to facilitate share purchases through open market purchases, privately-negotiated transactions, or otherwise in compliance with Rule 10b - 18 under the Securities Exchange Act of 1934. The 10b5 - 1 Plan provides for an aggregate purchase of currently outstanding common stock up to $ 30  million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.    The below table shows the repurchases of equity securities related to the share repurchase program during the fourth quarter of the fiscal year ended December 31, 2022 :   Period   Total Number of Shares Purchased     Average Price Paid per Share     Total Number of Shares Purchased as Part of Publicly Announced Programs     Maximum Amount that May Yet Be Used to Purchase Shares Under the Program   November 1, 2022 - November 30, 2022     288,758     $ 5.21       288,758     $ 28,500,463   December 1, 2022 - December 31, 2022     282,163     $ 5.34       282,163     $ 27,000,767   Total   570,921           570,921           F- 39 Table of Contents   The following table shows the repurchases of equity securities related to the share repurchase program after December 31, 2022 through March 31, 2023:   Period   Total Number of Shares Purchased     Average Price Paid per Share     Total Number of Shares Purchased as Part of Publicly Announced Programs     Maximum Amount that May Yet Be Used to Purchase Shares Under the Program   January 1, 2023 - January 31, 2023     350,832     $ 4.29       350,832     $ 25,502,669   February 1, 2023 - February 28, 2023     326,992     $ 4.61       326,992     $ 24,003,172   March 1, 2023 - March 31, 2023     303,176     $ 4.97       303,176     $ 22,503,206   Total     981,000               981,000             The Company continues to purchase shares under the 10b5 - 1 Plan for share repurchases from and including April  2023.   In connection with the RBL facility, the Company is required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase. As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, we may make distributions, buyback shares, or repurchase stock without further approval. In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock. For the year ended December 31, 2022, no specific approval or waivers were required for the Company to make distributions or repurchase stock.    The actual timing number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, the Company's stock price, general business and market conditions, and alternative investment opportunities. Under the Plan, the Company’s third -party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, would have authority to purchase the Company’s common stock in accordance with the terms of the Plan.   Merged Concession Agreement   On January 20, 2022, prior to the consummation of the Arrangement, TransGlobe announced a fully executed concession agreement "Merged Concession Agreement" with the Egyptian General Petroleum Corporation (“EGPC”) that merged the  three existing Eastern Desert concessions with a 15 -year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $ 15.0 million and signature bonus of $ 1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment of $ 10.0 million. In accordance with the Merged Concession. The Company will make three  further annual equalization payments of $ 10.0 million each beginning February 1, 2024  until February 1, 2026. VAALCO recorded modernization payment liabilities of $ 35.5  million at December 31, 2022.  On the consolidated balance sheet, $ 9.9 million of the modernization payment liability was recorded in the line item "Accrued liabilities and other" and $ 25.6  million was recorded in "Other long-term liabilities". VAALCO agreed to substitute the 2023 payment and issue a $ 10.0 million credit against receivables owed from EGPC for the amount due on February 1, 2023.   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 ( the "Merged Concession Effective Date") for a total of $ 150 million commencing on the Merged Concession Effective Date"). Through December 31, 2022, all investments have exceeded the five -year minimum $50 million threshold and any excess carries forward to offset against subsequent five -year commitments.    As the Merged Concession Agreement is effective as of February 1, 2020, there will be effective date adjustment 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. In accordance with GAAP, the Company has recognized a receivable in connection with the effective date adjustment of $ 67.5  million as of October 13, 2022, based on historical realized prices. However, the cumulative value to be received as a result of the effective date adjustment is currently being finalized with the EGPC and could result in a range of outcomes based on the final price per barrel negotiated. As of December 31, 2022, $ 17.2  of the effective date adjustment has been offset by amounts otherwise due to EGPC and the remaining $ 50.3  million is recorded on the consolidated balance sheet in Receivables-Other, net.   Other contractual commitments   In August 2020, the Company entered into an agreement to acquire approximately 1,000 square kilometers of 3 -D seismic data in the Company’s Etame Marin block. The acquisition was completed in the fourth quarter of 2020 and the processing of the seismic data began in January 2021. The cost, net to VAALCO, is approximately $ 2.2 million or $ 3.4 million gross.   F- 40 Table of Contents   In June 2021, the Company entered into a short-term agreement with an affiliate of Borr Drilling Limited to drill a minimum of three wells with options to drill additional wells. The 2021/2022 drilling program commenced in December 2021 and was completed in November 2022.     13. DEBT   As of  December 31, 2022 and 2021 , the Company had no outstanding debt.    RBL Facility   On May 16, 2022, the Borrower entered into the Facility Agreement by and among the Company, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C., as security agent, and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $ 50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $ 50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $ 6.25 million.   The Facility provides for determination of the borrowing base asset based on the Company’s proved producing reserves in Gabon and a portion of the Company's proved undeveloped reserves in Gabon. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.    Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00 % until the third anniversary of the Facility Agreement or (ii) 6.25 % from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).   Pursuant to the Facility Agreement, the Company shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35 % per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20 % per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.   The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $ 10.0 million. As of December 31, 2022 , the Company's borrowing base was $ 50.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. At December 31, 2022 , the Company was in compliance with all debt covenants and had no outstanding borrowings under the facility. With regard to the requirement that the Company deliver its fiscal year 2022 annual financial statements to Glencore within 90 days of the end of each fiscal year, the Company has requested and received an extension until April 17, 2023.    The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).   Deferred financing costs incurred in connection with securing the Facility were $ 1.9  million, $ 2.1  million net of amortization of $ 0.2  million, which is carried in the accompanying consolidated balance sheets in the line item "Other long-term assets" and is amortized on a straight-line basis, which approximates the effective interest method, over the term of the Facility and included in interest expense in the accompanying consolidated statements of operations and comprehensive income (loss).   ATB Facility   In connection with the Arrangement with TransGlobe in October 2022, and prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and liabilities owed under TransGlobe’s credit facility with ATB Financial (the "ATB Facility"), representing approximately Canadian $ 4.1 million. On December 19, 2022, TransGlobe, as an indirect wholly-owned subsidiary of the Company, voluntarily delivered a notice of termination to ATB Financial relating to the ATB Facility. As of December 31, 2022, no amounts were drawn on the revolving loan facility. On January 5, 2023, the ATB Facility was formally closed. Termination of the ATB Facility will not affect the Company's $ 50.0 million senior secured reserve-based revolving credit facility with Glencore.   F- 41 Table of Contents       14. LEASES   Under the leasing standard that became effective January  1, 2019, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments.   Practical Expedients The Company elected to use all the practical expedients, effectively carrying over its previous identification and classification of leases that existed as of January 1,  2019. Additionally, a lessee may elect not to recognize ROU assets and liabilities arising from short-term leases provided there is no purchase option the entity is likely to exercise. The Company has elected this short-term lease exemption.   Operating leases The Company is currently a party to several lease agreements for the corporate office, a drilling rig, rental of marine vessels and helicopters, warehouse and storage facilities, equipment and the FPSO. The duration for these agreements ranges from 6 to 27  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 the FPSO, the marine vessels, helicopter, certain equipment and warehouse and storage facilities used in the joint operations includes the gross amount of the lease components.   During the third quarter of 2019, the Company notified the lessor of the FPSO of its intent to extend the lease term by the first option that extends the FPSO lease to September 2021. Similarly, during the third quarter of 2020, the Company gave notification to extend the FPSO lease to September 2022.   On September 9, 2022, the Company entered into an addendum to the FPSO contract which extends the contract from September 2022 through October 4, 2022 and sets forth both the Company’s and lessor's rights and obligations with respect to demobilization and decommissioning. Under ASC 842, the Company was required to reassess the lease for lease classification at the time the Company entered into the amendment. Accordingly, the Company assessed the lease as a short-term lease.   The marine vessels and certain equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the level of production or the number of days or hours the asset is deployed, or the number of persons onboard the vessel. 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 used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. The duration for these agreements ranges from 10 to 117  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.   F- 42 Table of Contents   On February 15, 2022, the Company signed a contract for a finance lease of generators and related parts. The related ROU asset and lease liability was recorded on the lease commencement date of February 15, 2022.   In August 2021, the Company signed the FSO agreements to lease a FSO to replace the current FPSO whose term ended in October 2022. Under the terms of the FSO agreements, a third party is expected to modify the leased vessel in order to meet the Company’s crude-oil production requirements. The vessel arrived on location in the Etame Marin block in August 2022. On October 19, 2022, the Company signed the final acceptance certificate at which time control of the FSO vessel transferred to the Company.    All leases For all leases that contain an option to extend the initial lease term, the Company has evaluated whether it will extend the lease beyond the initial lease term. When the Company believes it will utilize these leased assets beyond the initial lease term, those payments have been included in the calculation for 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, 2022 and 2021 , the components of the lease costs and supplemental information was as follows:       Year Ended December 31,       2022     2021     2020   Lease cost:   (in thousands)   Finance lease cost (1)   $ 3,682     $ —     $ —   Operating lease cost     11,040       17,692       17,528   Short-term lease cost (2)     5,213       2,258       1,408   Variable lease cost (3)     4,513       6,188       7,572   Total lease expense     24,448       26,138       26,508   Lease costs capitalized     4,127       232       3,456   Total lease costs   $ 28,575     $ 26,370     $ 29,964     ( 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.   F- 43 Table of Contents   Other information:       2022     2021     2020   Other information:                         Cash paid for amounts included in the measurement of lease liabilities:                         Financing cash flows attributable to finance leases   $ 3,039     $ —     $ —   Weighted-average remaining lease term (in years)     9.65       —       —   Weighted-average discount rate     4.59 %     —       —                             Operating cash flows attributable to operating leases   $ 19,300     $ 23,925     $ 26,178   Weighted-average remaining lease term (in years)     1.35       0.91       1.80   Weighted-average discount rate     9.91 %     5.91 %     6.09 %   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,       2022     2021     2020       (in thousands)   Finance lease cost   $ 2,188     $ —     $ —   Production expense     12,222       13,457       7,904   General and administrative expense     160       193       197   Lease costs billed to the joint venture owners     11,390       12,573       20,692   Total lease expense     25,960       26,223       28,793   Lease costs capitalized     2,615       147       1,171   Total lease costs   $ 28,575     $ 26,370     $ 29,964     The following table describes the future maturities of the Company’s operating lease liabilities at December 31, 2022 :       Operating Leases     Finance Leases   Year   (in thousands)   2023   $ 2,478     $ 11,619   2024     671       11,495   2025     33       13,495   2026     —       13,893   2027     —       12,350   Thereafter     —       42,097         3,182       104,949   Less: imputed interest     182       18,890   Total lease liabilities   $ 3,000     $ 86,059     Under the joint operating agreements, other joint venture owners are obligated to fund $ 44.6  million of the $ 108.1  million in future lease liabilities as of December 31, 2022 .   F- 44 Table of Contents     15. CURRENT ACCRUED LIABILITIES AND OTHER   Accrued liabilities and other balances were comprised of the following:       As of December 31, 2022     As of December 31, 2021       (in thousands)   Accrued accounts payable invoices   $ 28,360     $ 11,967   Gabon DMO, PID and PIH obligations     10,509       9,465   Derivative liability - crude oil swaps     —       4,806   Capital expenditures     26,618       11,327   Stock appreciation rights – current portion     570       609   Accrued wages and other compensation     8,161       2,124   ARO Obligation     306       6,745   Egypt Modernization Payments     9,933       —   Other     6,935       2,401   Total accrued liabilities and other   $ 91,392     $ 49,444       16. SHAREHOLDERS ’ EQUITY   On October 13, 2022, in connection with the closing of the Arrangement, the total number of authorized shares of common stock of the Company was increased from 100 million to 160 million and VAALCO issued approximately 49.3 million shares to TransGlobe's shareholders.   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, 2022 or 2021 .   Treasury stock   On November 1, 2022, the Company announced that the board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022.  The Plan provides for an aggregate purchase of currently outstanding common stock up to $ 30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.   The below table shows the repurchases of the Company's equity securities during the fourth quarter of the fiscal year ended December 31, 2022 :   Period   Total Number of Shares Purchased     Average Price Paid per Share     Total Number of Shares Purchased as Part of Publicly Announced Programs     Maximum Amount that May Yet Be Used to Purchase Shares Under the Program   November 1, 2022 - November 30, 2022     288,758     $ 5.21       288,758     $ 28,500,463   December 1, 2022 - December 31, 2022     282,163     $ 5.34       282,163     $ 27,000,767   Total   570,921           570,921           F- 45 Table of Contents   For the majority of restricted stock awards granted by the Company, the number of shares issued to the participant on the vesting date are net of shares withheld to meet applicable tax withholding requirements. In addition, when options are exercised, the participant may elect to remit shares to the Company to cover the tax liability and the cost of the exercised options. When this happens, the Company adds these shares to treasury stock and pays the taxes on the participant’s behalf.   Although these withheld shares are not issued or considered common stock repurchases under the Company’s stock repurchase program, they are treated as common stock repurchases in the financial statements as they reduce the number of shares that would have been issued upon vesting.      17. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS   The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Board of Directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan ( “2014 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, 2022 , 3,870,496  shares were available for future grants.   For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one -for- one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.   As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense and production expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the years ended December 31, 2022, 2021 and 2020 , the Company settled in cash $ 0.8  million, $ 3.3  million and $ 0.3  million, respectively, for SARs. During the years ended December 31, 2022, 2021 and 2020 , the Company received in cash $ 0.3  million, $ 1.4  million and $ 0.1  million, respectively from stock option exercises. Because the Company does not pay significant U.S. federal income taxes, no amounts were recorded for future tax benefits.       Year Ended December 31,       2022     2021     2020       (in thousands)   Stock-based compensation - equity awards   $ 2,045     $ 1,060     $ 848   Stock-based compensation - liability awards     155       1,399       ( 734 ) Total stock-based compensation   $ 2,200     $ 2,459     $ 114     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 March 2022, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 241,358 shares at an exercise price of $ 6.41 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 $ 7.37 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 $ 8.48 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 $ 9.75 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.   F- 46 Table of Contents   The Company used the Monte Carlo simulation to calculate the grant date fair value of performance stock option awards. The fair value of these awards will be amortized to expense over the derived service period of the option.   For options that do not contain a market or performance condition, the Company uses the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the service period of the option.   During the year ended December 31, 2022, 2021 and 2020 the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo model in 2022 and 2021 and Black-Scholes models.       Year Ended December 31,       2022     2021     2020   Weighted average exercise price - ($/share)   $ 6.41     $ 3.14     $ 1.23   Expected life in years     6.0       6.0       6.0   Average expected volatility     72 %     75 %     74   Risk-free interest rate     1.98 %     0.95 %     0.42   Expected dividend yield     2.30 %     —       —   Weighted average grant date fair value - ($/share)   $ 2.84     $ 2.07     $ 0.79     Stock option activity associated with the Monte Carlo model for the year ended December 31, 2022 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, 2022     359     $ 1.96                   Granted     241       6.41                   Exercised     ( 47 )     ( 1.23 )                 Unvested shares forfeited     ( 109 )     ( 4.03 )                 Vested shares expired     —       —                   Outstanding at December 31, 2022     444     $ 3.95       7.15     $ 632   Exercisable at December 31, 2022     147     $ 1.83       3.92     $ 400     The intrinsic value of a performance stock option awards is the amount that the current market value of the underlying stock exceeds the exercise price of the award. The intrinsic performance stock option awards exercised in 2022 was $ 0.2 million.   As of December 31, 2022, unrecognized compensation cost related to outstanding performance stock option awards was $ 0.4  million, which is expected to be recognized over a weighted average period of  2.0  years.   During the year ended December 31, 2022, no  shares were added to treasury as a result of tax withholding on performance stock option awards exercised.   F- 47 Table of Contents   Stock option activity associated with the Black-Scholes model for the year ended December 31, 2022 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, 2022     615     $ 1.58                   Granted     —       —                   Exercised     ( 228 )     ( 1.12 )                 Unvested shares forfeited     —       —                   Vested shares expired     —       —                   Outstanding at December 31, 2022     387     $ 1.86       0.83     $ 1,045   Exercisable at December 31, 2022     387     $ 1.86       0.83     $ 1,045     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 2022 ,  2021 and 2020 was $ 1.2 million, $ 1.6 million, and $ 43  thousand, respectively.   As of December 31, 2022 , unrecognized compensation cost related to outstanding stock options was none.   During the year ended December 31, 2022 , 49,063  shares were added to treasury as a result of tax withholding on options exercised. During the year ended December 31, 2021 , 464,671  shares were added to treasury as a result of tax withholding on options exercised.   Restricted shares   Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three -year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty ( 50 ) weeks following the date of grant). In March 2022, the Company issued 353,424 shares of service-based restricted stock to employees, with a grant date fair value of $ 6.41 per share. In addition, in June 2022, the Company issued 30,687 shares of service-based restricted stock to directors, with a grant date fair value of $ 8.31 per share. The vesting of the foregoing shares is dependent upon, among other things, the employees’ and directors’ continued service with the Company.   The following is the activity for the Company's restricted stock for the year ended December 31, 2022 :       Restricted Stock     Weighted Average Grant Date Fair Value       (in thousands)           Non-vested shares outstanding at January 1, 2022     741     $ 2.36   Awards granted     384       6.56   Awards vested     ( 334 )     2.25   Awards forfeited     ( 126 )     3.68   Non-vested shares outstanding at December 31, 2022     665     $ 4.59     The total fair value of vested restricted stock awards during 2022 ,  2021 and 2020 was $ 2.4 million, $ 1.8  million, and $ 0.2  million, respectively. The weighted average grant date fair value per share of restricted stock awards, which vested during 2022 ,  2021 and 2020 , was $ 2.25 , $ 1.28  and $ 1.35 , respectively.   As of December 31, 2022 , unrecognized compensation cost related to restricted stock totaled $ 1.3 million and is expected to be recognized over a weighted average period of  1.4 year.   F- 48 Table of Contents   During the year ended December 31, 2022 , 69,135 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the year ended December 31, 2021 , 68,134 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.   In connection with the Arrangement with TransGlobe and pursuant to the Arrangement Agreement, at the effective time of the Arrangement, certain awards previously issued to TransGlobe’s key employees and board members who continued their relationship as employees or board members of VAALCO following the Arrangement, will continue to be governed by the applicable TransGlobe plan, provided that each such applicable plan has been amended to provide that VAALCO common stock shall be issuable in lieu of cash or TransGlobe common stock with respect to TransGlobe’s deferred share units (“DSU”s), performance share units (“PSU”s) and restricted stock units (“RSU”s), in each case, based on the exchange ratio in the Arrangement. For the PSUs that will remain outstanding following the effective time of the Arrangement as described in the immediately preceding sentence, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200 % for PSUs granted in 2020 and 2021; and 64.4 % for PSUs granted in 2022.     On the effective date of the Arrangement, October 13, 2022, the combined fair value of the DSUs, PSU's and RSU's liability from TransGlobe was $ 6.0 million. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards from cash-settled liability awards to equity awards. On the date of this conversion, the awards were revalued based on VAALCO’s share price, and the Company recognized a gain of $ 0.6 million in its consolidated statements of operations and comprehensive income (loss).    RSUs were issued to directors, officers and employees of TransGlobe in the ordinary course of business prior to the Arrangement. Each RSU vests annually over a three -year period. On December 16, 2022, Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. RSU activity for the period December 16, 2022 through December 31, 2022  is presented in the table below:       Restricted Stock     Weighted Average Conversion Date Fair Value       (in thousands)           Non-vested shares outstanding at December 16, 2022     —     $ —   Awards converted     386       4.27   Awards vested     ( 3 )     4.27   Awards forfeited     —       —   Non-vested shares outstanding at December 31, 2022     383     $ 4.27     The total fair value of vested RSU awards during 2022  was $14 thousand. The weighted average grant date fair value per share of RSU, which vested during 2022 , was $ 4.27 .   As of December 31, 2022, unrecognized compensation cost related to RSU’s totaled $ 0.5 million and is expected to be recognized over a weighted average period of  1.7 years.   During the year ended December 31, 2022,  1,381 shares were added to treasury as a result of tax withholding on the vesting of RSU’s.   F- 49 Table of Contents   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 Arrangement, the applicable vesting percentage was determined by the TransGlobe board of directors to be 200% for PSUs granted in 2020 and 2021; and 64.4% for PSUs granted in 2022.  All PSUs granted vest on the third anniversary of their grant date. On December 16, 2022, the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. PSU activity for the period December 16, 2022 through December 31, 2022 is presented in the table below:       Restricted Stock     Weighted Average Conversion Date Fair Value       (in thousands)           Non-vested shares outstanding at December 16, 2022     —     $ —   Awards converted     690       4.27   Awards vested     —       —   Awards forfeited     —       —   Non-vested shares outstanding at December 31, 2022     690     $ 4.27     No PSU awards vested from October 14, 2022 through December 31, 2022.   As of December 31, 2022, unrecognized compensation cost related to PSU’s totaled $ 0.7 million and is expected to be recognized over a weighted average period of  1.1 years.   DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's   Board of Directors. On December 16, 2022,  the Compensation Committee determined that the awards would be settled in shares from the 2020 Plan, thereby converting all the awards to equity awards instead of cash-settled liability awards. DSU activity for the period December 16, 2022 through December 31, 2022 is presented in the table below:       Restricted Stock     Weighted Average Conversion Date Fair Value       (in thousands)           Non-vested shares outstanding at December 16, 2022     —     $ —   Awards converted     460       4.27   Awards vested     ( 460 )     4.27   Awards forfeited     —       —   Non-vested shares outstanding at December 31, 2022     —     $ —     F- 50 Table of Contents   Stock appreciation rights ( “ SARs ” )   SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s Board of Directors.   During the years ended December 31, 2022 and 2021 , the Company did not grant SARs to employees or directors. SAR activity for the year ended December 31, 2022 is provided below:       Number of Shares Underlying SARs     Weighted Average Exercise Price Per Share     Term     Aggregate Intrinsic Value       (in thousands)             (in years)     (in thousands)   Outstanding at January 1, 2022     362     $ 1.81                   Granted     —       —                   Exercised     ( 160 )     1.74                   Unvested SARs forfeited     —       —                   Vested SARs expired     —       —                   Outstanding at December 31, 2022     202     $ 1.87       0.85     $ 542   Exercisable at December 31, 2022     202     $ 1.87       0.85     $ 542     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 2022,   2021 and 2020 was $ 0.8 million.   SARs 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.   Other Benefit Plans   The Company has adopted forms of change in control agreements for its named executive officers and certain other officers of the Company as well as a severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements and participants in the severance plan will be entitled to receive 100 % and 50 %, respectively, of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months. In addition, certain named executive officers will receive 75 % of their target bonus. Some of the named executive officers are also entitled to severance payments under their employment agreements.   The Company sponsors a 401 (k) plan, with a company match feature, for the employees. Costs of $ 0.4  million for the year ended December 31, 2022 , $ 0.3  million for the year ended December 31, 2021 , and $ 0.4  million for the year ended December 31, 2020, respectively, were incurred for the Company’s matching contribution and for administering the plan.   F- 51 Table of Contents     18.  RELATED PARTY TRANSACTIONS   On November 7, 2022, the Company promoted Thor Pruckl (“Mr. Pruckl” )  to the position of Chief Operating Officer of the Company, effective November 7, 2022.    On March 14, 2022, in the ordinary course of business, the Company entered into a professional services agreement (the “Services Agreement”) with J. Pruckl Holdings Ltd. (“Pruckl Holdings”), an entity owned and controlled by James Pruckl, Mr. Pruckl’s son. Under the Services Agreement, Pruckl Holdings designates James Pruckl to render project contract engineering services for the Company that include pipeline in-line data analysis, jacket structures and subsea pipeline inspections and other related services in connection with the Etame Marin block located at offshore Gabon in West Africa. As of December 31, 2022, the Company has been invoiced approximately $ 177 thousand in the aggregate and approximately $ 33 thousand was still outstanding at December 31, 2022,  pursuant to the Services Agreement.     19.  OTHER COMPREHENSIVE INCOME   The Company’s other comprehensive income of $ 1.2  million is for the period of October 14 – December 31, 2022, the period after the acquisition of TransGlobe. The functional currency of TransGlobe Energy Corporation is the Canadian Dollar. All of the Company’s other comprehensive income arises from the currency translation of TransGlobe Energy Corporation to USD.   The components of accumulated other comprehensive income are as follows:      Currency Translation Adjustments                           (in thousands)   Balance at December 31, 2021   $ —   Accumulated other comprehensive income (loss) before reclassifications     1,179   Amounts reclassified from accumulated other comprehensive income (loss)     —   Balance at December 31, 2022   $ 1,179       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 (Africa), and onshore in Egypt and Canada.    F-52 Table of Contents   Costs Incurred for Acquisition, Exploration and Development Activities   Costs incurred during the year:   Gabon     Egypt     Canada     Total   Year Ended December 31, 2022   (in thousands)   Exploration costs - capitalized   $ 47     $ —     $ —     $ 47   Exploration costs - expensed     258       —       —       258   Acquisition of properties     —       170,982       104,390       275,372   Development costs     162,328       7,515       2,187       172,030   Total   $ 162,633     $ 178,497     $ 106,577     $ 447,707                                         Gabon     Total                   Year Ended December 31, 2021   (in thousands)                   Exploration costs - capitalized   $ 254     $ 254                   Exploration costs - expensed     1,579       1,579                   Acquisition of properties     42,744       42,744                   Development costs     36,223       36,223                   Total   $ 80,800     $ 80,800                                                         Gabon     Total                   Year Ended December 31, 2020   (in thousands)                   Exploration costs - capitalized   $ 8,484   (1)   $ 8,484                   Exploration costs - expensed     3,588       3,588                   Acquisition of properties     —       —                   Development costs     731       731                   Total   $ 12,803     $ 12,803                   (1) -  Primarily associated with the Southeast Etame 4P appraisal wellbore.   Capitalized Costs Relating to crude oil, natural gas and NGLs Producing Activities   Capitalized costs pertain to the producing activities in Gabon, Egypt and Canada and to undeveloped leasehold in Gabon, Egypt, Canada and Equatorial Guinea.       As of December 31,       2022     2021   Capitalized costs:   (in thousands)   Properties not being amortized   $ 71,670     $ 55,488   Properties being amortized     1,406,888       488,756   Total capitalized costs   $ 1,478,558     $ 544,244   Less accumulated depletion, amortization and impairment     (986,952 )     (451,498 ) Net capitalized costs   $ 491,606     $ 92,746       F-53 Table of Contents   Results of Operations for crude oil, natural gas and NGLs Producing Activities   For Egypt and Canada, all activity pertains to the period of October 14, 2022 - December 31, 2022, after the acquisition of TransGlobe.                                                  International                       Gabon     Egypt     Canada     U.S.     Total   Year Ended December 31, 2022               (In thousands)                   Revenues   $ 306,775     $ 37,710     $ 9,841     $ —     $ 354,326   Production costs and other expense (1)     (108,701 )     (11,936 )     (1,972 )     —       (122,609 ) Depreciation, depletion, amortization     (34,651 )     (10,444 )     (2,921 )     —       (48,016 ) Exploration expenses     (258 )     —       —       —       (258 ) Other operating expense     38       —       —       —       38   Bad debt recovery (expense)     (2,743 )     —       —       —       (2,743 ) Income tax benefit (expense)     (16,641 )     (6,254 )     —       —       (22,895 ) Results from crude oil and natural gas producing activities   $ 143,819     $ 9,076     $ 4,948     $ —     $ 157,843                                                 Gabon     U.S.     Total                   Year Ended December 31, 2021         (In thousands)                         Crude oil and natural gas sales   $ 199,075     $ —     $ 199,075                   Production costs and other expense (1)     (81,984 )     —       (81,984 )                 Depreciation, depletion, amortization     (20,972 )     —       (20,972 )                 Exploration expenses     (1,579 )     —       (1,579 )                 Other operating expense     (440 )     —       (440 )                 Bad debt recovery (expense)     (875 )     —       (875 )                 Income tax benefit (expense)     (9,626 )     —       (9,626 )                 Results from crude oil and natural gas producing activities   $ 83,599     $ —     $ 83,599                                                                 Gabon     U.S.     Total                   Year Ended December 31, 2020         (In thousands)                         Crude oil and natural gas sales   $ 67,176     $ —     $ 67,176                   Production costs and other expense (1)     (38,176 )     (5 )     (38,181 )                 Depreciation, depletion, amortization     (9,028 )     —       (9,028 )                 Exploration expenses     (3,588 )     —       (3,588 )                 Impairment of proved properties     (30,625 )     —       (30,625 )                 Other operating expense     (1,669 )     —       (1,669 )                 Bad debt recovery (expense)     (1,165 )     —       (1,165 )                 Income tax benefit (expense)     10,785       —       10,785                   Results from crude oil and natural gas producing activities   $ (6,290 )   $ (5 )   $ (6,295 )                   (1)  Includes local general and administrative expenses but excludes corporate general and administrative expenses and allocated corporate overhead.   F-54 Table of Contents   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 .”   For Egypt and Canada, all activity pertains to the period of October 14, 2022 - December 31, 2022, after the acquisition of TransGlobe.        Oil       Gabon     Egypt     Canada     Total   Proved reserves:   (MBbls)     (MBbls)     (MBbls)     (MBbls)   Balance at January 1, 2020     4,966       —       —       4,966   Production     (1,776 )     —       —       (1,776 ) Extensions and discoveries     497       —       —       497   Revisions of previous estimates     (471 )     —       —       (471 ) Balance at December 31, 2020     3,216       —       —       3,216   Production     (2,599 )     —       —       (2,599 ) Purchase of reserves     2,633       —       —       2,633   Revisions of previous estimates     7,968       —       —       7,968   Balance at December 31, 2021     11,218       —       —       11,218   Production     (2,971 )     (639 )     (108 )     (3,718 ) Purchase of reserves     —       9,216       3,715       12,931   Extensions and discoveries     —       —       —       —   Revisions of previous estimates     1,972       —       —       1,972   Balance at December 31, 2022     10,219       8,577       3,607       22,403           Oil       Gabon     Egypt     Canada     Total       (MBbls)     (MBbls)     (MBbls)     (MBbls)   Year-end proved developed reserves:                                 2022     10,219       8,001       1,722       19,942   2021     7,227       —       —       7,227   2020     3,216       —       —       3,216   Year-end proved undeveloped reserves:                                 2022     —       576       1,885       2,461   2021     3,991       —       —       3,991   2020     —       —       —       —           Natural Gas       Gabon     Egypt     Canada     Total   Proved reserves:   (MMcf)     (MMcf)     (MMcf)     (MMcf)   Balance at December 31, 2021     —       —       —       —   Production     —       —       (396 )     (396 ) Purchase of reserves     —       —       16,935       16,935   Extensions and discoveries     —       —       —       —   Revisions of previous estimates     —       —       —       —   Balance at December 31, 2022     —       —       16,539       16,539       F-55 Table of Contents       Natural Gas       Gabon     Egypt     Canada     Total       (MMcf)     (MMcf)     (MMcf)     (MMcf)   Year-end proved developed reserves:                                 2022     —       —       11,023       11,023   Year-end proved undeveloped reserves:                                 2022     —       —       5,516       5,516         NGLs       Gabon     Egypt     Canada     Total   Proved reserves:   (MBbls)     (MBbls)     (MBbls)     (MBbls)   Balance at December 31, 2021     —       —       —       —   Production     —       —       (73 )     (73 ) Purchase of reserves     —       —       2,870       2,870   Extensions and discoveries     —       —       —       —   Revisions of previous estimates     —       —       —       —   Balance at December 31, 2022     —       —       2,797       2,797           NGLs       Gabon     Egypt     Canada     Total       (MBbls)     (MBbls)     (MBbls)     (MBbls)   Year-end proved developed reserves:                                 2022     —       —       1,855       1,855   Year-end proved undeveloped reserves:                                 2022     —       —       942       942     F-56 Table of Contents       Total Reserves (1)       Gabon     Egypt     Canada     Total   Proved reserves:   (MBoe)     (MBoe)     (MBoe)     (MBoe)   Balance at January 1, 2020     4,966       —       —       4,966   Production     (1,776 )     —       —       (1,776 ) Extensions and discoveries     497       —       —       497   Revisions of previous estimates     (471 )     —       —       (471 ) Balance at December 31, 2020     3,216       —       —       3,216   Production     (2,599 )     —       —       (2,599 ) Purchase of reserves     2,633       —       —       2,633   Revisions of previous estimates     7,968       —       —       7,968   Balance at December 31, 2021     11,218       —       —       11,218   Production     (2,971 )     (639 )     (247 )     (3,857 ) Purchase of reserves     —       9,216       9,408       18,624   Extensions and discoveries     —       —       —       —   Revisions of previous estimates     1,972       —       —       1,972   Balance at December 31, 2022     10,219       8,577       9,161       27,957   (1) - To convert Natural Gas to MBoe, MMcf is divided by 6.   The proved developed reserves are located offshore Gabon, in Egypt and in Canada. In 2022, operations in Gabon had 2.0 MMBbls of positive revision of reserves due to the 2021/2022 drilling campaign. 0.7 MMBbls of the positive revision was due to performance and the remaining 1.3 MMBbls of positive revisions was due to price. The company also acquired 9.2 MMBbls in oil reserves in Egypt and 9.4 MMBoe of reserves in Canada as a result of the TransGlobe acquisition. In 2021, the Company added 2.6 MMBbls of reserves due the acquisition of Sasol’s interest in the Etame Marin block. In addition, the Company added 8.0 MMBbls due to positive revisions. The positive revision of 8.0 MMBbls was due to positive revision of 3.0 MMBbls due to price and positive revisions of 5.0 MMBbls due to performance.    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-57 Table of Contents   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, 2022, 2021 and 2020.       International   (In thousands)   Gabon     Egypt     Canada     Total   Year Ended December 31, 2022                                 Future cash inflows   $ 1,035,667     $ 729,236     $ 506,247     $ 2,271,150   Future production costs     (450,639 )     (273,260 )     (135,082 )     (858,981 ) Future development costs (1)     (58,057 )     (12,079 )     (69,346 )     (139,482 ) Future income tax expense     (248,024 )     (146,835 )     —       (394,859 ) Future net cash flows     278,947       297,062       301,819       877,828   Discount to present value at 10% annual rate     (34,520 )     (70,174 )     (148,669 )     (253,363 ) Standardized measure of discounted future net cash flows   $ 244,427     $ 226,888     $ 153,150     $ 624,465   Year Ended December 31, 2021                                 Future cash inflows   $ 782,006     $ —     $ —     $ 782,006   Future production costs     (416,819 )     —       —       (416,819 ) Future development costs (1)     (128,984 )     —       —       (128,984 ) Future income tax expense     (116,637 )     —       —       (116,637 ) Future net cash flows     119,566       —       —       119,566   Discount to present value at 10% annual rate     (20,308 )     —       —       (20,308 ) Standardized measure of discounted future net cash flows   $ 99,258     $ —     $ —     $ 99,258   Year Ended December 31, 2020                                 Future cash inflows   $ 138,328     $ —     $ —     $ 138,328   Future production costs     (99,418 )     —       —       (99,418 ) Future development costs (1)     (10,605 )     —       —       (10,605 ) Future income tax expense     (13,921 )     —       —       (13,921 ) Future net cash flows     14,384       —       —       14,384   Discount to present value at 10% annual rate     348       —       —       348   Standardized measure of discounted future net cash flows   $ 14,732     $ —     $ —     $ 14,732   (1)  Includes costs expected to be incurred to abandon the properties, where applicable.   International income taxes represent amounts payable to the Government of Gabon on Profit Oil as final payment of corporate income taxes, and domestic income taxes (including other expenses treated as taxes).    F-58 Table of Contents   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,       2022     2021     2020       (in thousands)   Balance at beginning of period   $ 99,258     $ 14,733     $ 70,431   Sales of crude oil and natural gas, net of production costs     (233,421 )     (118,358 )     (29,878 ) Net changes in prices and production costs     264,804       126,668       (53,388 ) Extensions and discoveries     —       —       10,059   Revisions of previous quantity estimates     95,623       158,213       (10,885 ) Purchases     415,385       9,285       —   Changes in estimated future development costs     (23,243 )     (39,969 )     1,195   Development costs incurred during the period     101,495       2,629       731   Accretion of discount     9,926       2,752       10,086   Net change of income taxes     (121,490 )     (60,218 )     17,636   Change in production rates (timing) and other     16,128       3,523       (1,254 ) Balance at end of period   $ 624,465     $ 99,258     $ 14,733     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 guidelines of the SEC, estimates of future net cash flow from the properties and the present value thereof are made using an unweighted, arithmetic average of the first-day-of-the-month price for each of the 12 months of the year adjusted for quality, transportation fees and market differentials. Such prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For 2022, the average of such prices reflected a 45% increase during the year and were $100.35 per Bbl for crude oil from Gabon when compared to the average of such prices for 2021 of $69.10 per Bbl for crude oil from Gabon. Prices were between $84.76 and $85.65 per Bbl for crude oil from Egypt and $89.61 per Bbl for crude oil from Canada.   For 2022, the adjusted average price for our reserves associated with natural gas was $4.13 per MCF, $12.77 per Bbl for Ethane, $40.27 per Bbl for propane, $43.85 per Bbl for butane and $91.57 per Bbl for condensates.   Under the Etame PSC in Gabon, the Gabonese government is the owner of all crude oil, natural gas and NGLs mineral rights. The right to produce the crude oil, natural gas and NGLs is stewarded by the Directorate Generale de Hydrocarbures and the Etame PSC was awarded by a decree. Pursuant to the contract, the Gabon government receives a fixed royalty rate of 13%. Originally, under the Etame PSC, Gabonese government was not anticipated to take physical delivery of its allocated production. Instead, the Company was authorized to sell the Gabonese government’s share of production and remit the proceeds to the Gabonese government. Beginning in February 2018, the Gabonese government elected to take physical delivery of its allocated production volumes for Profit Oil (see discussion in Note 7 above).   F-59 Table of Contents   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 prepared by the independent reserve engineering firm of Netherland, Sewell & Associates, Inc.   The PSC for Block P in Equatorial Guinea entitles the Company to receive up to 70% of any future production after royalty deduction so long as there are amounts remaining in the Cost Account. Royalty rates are 10-16% depending on production rates. The Etame Consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 10% to 60% of the crude oil remaining after deducting the royalty and Cost Recovery. The percentage of “profit oil” paid to the government as tax is a function of cumulative production. In addition, Equatorial Guinea imposes a 25% income tax on net profits. The Block P PSC provides for a discovery to be reclassified into a development area with a term of 25 years. At December 31, 2022, the Company has no 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.   F-60